Hot-side method and system

ABSTRACT

The present disclosure is directed to the use of elemental or speciated iodine and bromine to control total mercury emissions.

CROSS REFERENCE TO RELATED APPLICATION

The present application is a continuation of U.S. application Ser. No.16/186,187, filed Nov. 9, 2018, now U.S. patent Ser. No. ______, whichis a continuation of U.S. application Ser. No. 15/488,244, filed Apr.14, 2017, now U.S. Pat. No. 10,124,293, which is a continuation of U.S.application Ser. No. 14/604,153, filed Jan. 23, 2015, now U.S. Pat. No.9,657,942, which is a continuation of U.S. application Ser. No.13/920,658, filed Jun. 18, 2013, now U.S. Pat. No. 8,951,487, which is acontinuation-in-part of U.S. application Ser. No. 13/281,066, filed Oct.25, 2011, now U.S. Pat. No. 8,524,179, which claims the benefits of U.S.Provisional Application Ser. No. 61/406,492, filed Oct. 25, 2010; and61/422,026, filed Dec. 10, 2010, both entitled “METHOD AND EQUIPMENT FORCONTROLLING MERCURY EMISSIONS FROM COAL-FIRED THERMAL PROCESSES”, whichare incorporated herein by this reference in their entirety.

FIELD

The disclosure relates generally to controlling mercury emissions andparticularly to controlling mercury emissions using halogen-containingadditives.

BACKGROUND

In response to the acknowledged threat that mercury poses to humanhealth and the environment as a whole, both federal and state/provincialregulation have been implemented in the United States and Canada topermanently reduce mercury emissions, particularly from coal-firedutilities (e.g., power plants), steel mills, cement kilns, wasteincinerators and boilers, industrial coal-fired boilers, and other coalcombusting facilities. For example, about 40% of mercury introduced intothe environment in the U.S. comes from coal-fired power plants. Newcoal-fired power plants will have to meet stringent new sourceperformance standards. In addition, Canada and more than 12 states haveenacted mercury control rules with targets of typically 90% control ofcoal-fired mercury emissions and other states are consideringregulations more stringent than federal regulations. Further U.S.measures will likely require control of mercury at more stringent ratesas part of new multi-pollutant regulations for all coal-fired sources.

The leading technology for mercury control from coal-fired power plantsis activated carbon injection (“ACI”). ACI is the injection of powderedcarbonaceous sorbents, particularly powdered activated carbon (“PAC”),upstream of either an electrostatic precipitator or a fabric filter baghouse. Activated or active carbon is a porous carbonaceous materialhaving a high adsorptive power.

Activated carbon can be highly effective in capturing oxidized (asopposed to elemental) mercury. Most enhancements to ACI have usedhalogens to oxidize gas-phase elemental mercury so it can be captured bythe carbon surface. ACI technology has potential application to thecontrol of mercury emissions on most coal-fired power plants, even thoseplants that may achieve some mercury control through control devicesdesigned for other pollutants, such as wet or dry scrubbers for thecontrol sulfur dioxide. ACI is a low capital cost technology. Thelargest cost element is the cost of sorbents. However, ACI has inherentdisadvantages that are important to some users. First, ACI is normallynot effective at plants configured with hot-side electrostaticprecipitators or higher temperature cold-side electrostaticprecipitators, because the temperature at which the particulates arecollected is higher than the temperature at which the carbon adsorbs themercury. Second, activated carbon is less effective for plants firinghigh- or medium-sulfur coal, plants using selective catalytic reduction(SCR) systems to control nitrogen oxide emissions where sulfur dioxidemay be converted to sulfur trioxide at the catalyst surface and plantsusing sulfur trioxide flue gas conditioning due to the interference ofsulfur trioxide with capture of mercury on the carbon surface. Anothertechnique to control mercury emissions from coal-fired power plants isbromine injection with ACI. Such a mercury control system is sold byAlstom Power Inc. under the trade names Mer-Cure™ or KNX™ and by NalcoMobotec Company under the trade name MerControl 7895™. Bromine isbelieved to oxidize elemental mercury and form mercuric bromide. Toremove mercury effectively, bromine injection is done at high rates,typically above 100 ppmw of the coal. At 100 ppmw without ACI or otherfactors such as high unburned carbon from coal combustion or thepresence of a flue gas desulfurization system, bromine has been reportedas resulting in a change of mercury emissions of about 40% lower thanthe uncontrolled mercury.

Bromine, when added at high concentrations such as 100 ppmw of the coalfeed, is problematic for at least two reasons. It can form HBr in theflue gas, which is highly corrosive to plant components, such asductwork. In particular, cold surfaces in the gas path, such as airpreheater internals, outlet ductwork, scrubber and stack liners, arevery susceptible to corrosion attack. Also at such high injection rates,a significant amount of bromine will be emitted from the stack and intothe environment. Bromine is a precursor to bromomethane,hydrobromofluorocarbons, chlorobromomethane and methyl bromide, whichare known ozone depletors in the earth's upper atmosphere.

SUMMARY

These and other needs are addressed by the various aspects, embodiments,and configurations of the present disclosure. The aspects, embodiments,and configurations are directed generally to the conversion of gas-phasemercury to a form that is more readily captured.

In one aspect, a method is provided that includes the steps:

(a) generating from a mercury-containing feed material amercury-containing gas stream comprising vapor-phase elemental mercuryand a vapor-phase halogen;

(b) contacting at least one of the mercury-containing feed material andthe mercury-containing gas stream with a reactive surface agent upstreamof an air preheater, reactive surface agent and vapor phase halogenconverting elemental mercury into ionic mercury and collecting the ionicmercury on the reactive surface agent; and

(c) removing the ionic mercury active agent and reactive surface agentfrom the mercury-containing gas stream.

An advantage of this aspect is temperature stability. Introducinghalogens with the coal with subsequent carbonaceous reactive surfaceagent (e.g., activated carbon) injection can result in superiortemperature stability of the collected particulate compared to the useof bromine-treated reactive surface agent, for example. This canparticularly be true when the activated carbon is brominated with asalt.

In one aspect, a method is provided that includes the steps:

(a) providing a mercury-containing gas stream comprising vapor-phaseelemental mercury;

(b) contacting the mercury-containing gas stream with a carbonaceousreactive surface agent upstream of an air preheater, the reactivesurface agent comprising at least one of iodine and bromine to collectthe ionic mercury on the reactive surface agent; and

(c) removing the mercury-loaded reactive surface agent from the gasstream.

The combined halogen and reactive surface agent can not only be costeffective but also efficacious, at surprisingly low concentrations, inpromoting the removal of both elemental and speciated mercury frommercury-containing gas streams. Compared to bromine and iodine in theabsence of a reactive surface agent, the reactive surface agent has beenfound to cost effectively promote the formation of particle-boundmercury species at relatively high temperatures.

Very low levels of halogen can enable or facilitate removal of mercuryeffectively in coal-fired systems, if excessively high acid gas speciescan be controlled. Mercury will generally not be removed effectively bycarbon sorbents or on fly ash in the presence of higher sulfur trioxideand/or nitrogen dioxide concentrations in the mercury-containing gasstream. A high concentration of acid gases (which high partial pressuretypically refers to a trioxide concentration of at least about 5 ppmv inthe mercury-containing gas stream and even more typically of at leastabout 10 ppmv and/or a nitrogen dioxide concentration of at least about5 ppmv and even more typically at least about 10 ppmv). The highersulfur trioxide concentration can be due to sulfur levels in the feedmaterial, catalytic oxidation of sulfur dioxide to sulfur trioxideacross the SCR and/or where SO₃ is injected to improve performance ofthe particulate removal device. The condensation temperature of sulfurtrioxide and/or nitrogen dioxide on a collection or sorbent surface canbe lower than the condensation temperatures of mercuric iodide andperiodic acid. As noted, condensed acid can displace sorbed mercury froma carbon sorbent particle surface.

By forming a mercury-containing particulate that can be collected in anelectrostatic precipitator or baghouse or reacting with collectedparticulate, the mercury can be removed prior to entering the wetscrubber. This can eliminate the potential for re-emission of elementalmercury from the scrubber, which is extremely difficult to control forvariable process conditions. It can also reduce or eliminate mercuryfrom the scrubber sludge.

When halogens are introduced with the feed material, the collectedmercury appears to be much more temperature stable than collectedmercury caused by introduction of halogens into the flue gas.Introducing halogens with coal, for example, with subsequent ACIinjection seems to result in much better temperature stability of themercury associated with the collected particulate than whenbromine-treated activated carbon is used, particularly when theactivated carbon is brominated with a salt.

Stability of captured mercury in fly ash or other retained particulatesolids is related to leachability and solubility of the mercury.Mercuric iodide, HgI₂, has a very low solubility in water, which issignificantly different from (less soluble than) other oxidized mercuryspecies such as HgCl₂ and HgBr₂. The solubility in water is more thantwo orders of magnitude lower than bromide or chloride species: HgCl₂ is73.25 g/l, HgBr₂ is 6.18 g/l, HgI₂ is 0.06 g/land Hgº is 5.73×10⁻⁰⁵ g/l.The lower solubility of captured HgI₂ will reduce the leachability infly ash and other solid particulates compared to other oxidized mercuryspecies.

The present disclosure can include a method having at least thefollowing steps:

(a) generating from a mercury-containing feed material amercury-containing gas stream comprising vapor-phase elemental mercuryand a vapor-phase halogen;

(b) passing the mercury-containing gas stream through a scrubber toremove a portion of the vapor-phase halogen and/or a halogen-containingderivative thereof and form a halogen-containing scrubbing medium and atreated gas stream; and

(c) removing the halogen from the halogen-containing scrubbing medium toform a treated scrubbing medium for recycle to the scrubber and aremoved halogen and/or halogen-containing material.

The halogen in the removed halogen and/or halogen-containing material iscommonly one or more of bromine and iodine.

The scrubber can be a wet or dry scrubber.

The scrubber can remove not only most of the vapor-phase halogen fromthe gas stream but also most of an acid gas from the gas stream. Forexample, the scrubber can be capable of removing one or more of HCl,HBr, and HF from the gas stream.

Most of the halogen on the halogen-containing scrubbing medium can beremoved as the removed halogen and/or halogen-containing material.

The halogen can be removed from the halogen-containing scrubbing mediumby one or more of membrane separation, precipitation, adsorption, and/orabsorption. For example, the halogen can be removed by one or more of anion exchange resin, solvent extraction, adsorption, absorption,precipitation, and membrane filtration.

The halogen-containing scrubbing medium can be contacted with an oxidantto assist halogen removal.

The halogen can oxidize elemental mercury in the gas stream, and theremoved halogen and/or halogen-containing material recycled to thegenerating step, whereby the vapor-phase halogen is derived from theremoved halogen and/or halogen-containing material. The removed halogenand/or halogen-containing material can be regenerated prior to recycle.

The mercury-containing feed material can be coal.

The vapor-phase halogen can be formed from a native halogen-content ofthe coal, a halogen-containing additive combusted with the coal, and/orintroduced into the gas stream downstream of a coal combustion zone.

These and other advantages will be apparent from the disclosure of theaspects, embodiments, and configurations contained herein.

“A” or “an” entity refers to one or more of that entity. As such, theterms “a” (or “an”), “one or more” and “at least one” can be usedinterchangeably herein. It is also to be noted that the terms“comprising”, “including”, and “having” can be used interchangeably.

“Absorption” is the incorporation of a substance in one state intoanother of a different state (e.g. liquids being absorbed by a solid orgases being absorbed by a liquid). Absorption is a physical or chemicalphenomenon or a process in which atoms, molecules, or ions enter somebulk phase—gas, liquid or solid material. This is a different processfrom adsorption, since molecules undergoing absorption are taken up bythe volume, not by the surface (as in the case for adsorption).

“Adsorption” is the adhesion of atoms, ions, biomolecules, or moleculesof gas, liquid, or dissolved solids to a surface. This process creates afilm of the adsorbate (the molecules or atoms being accumulated) on thesurface of the adsorbent. It differs from absorption, in which a fluidpermeates or is dissolved by a liquid or solid. Similar to surfacetension, adsorption is generally a consequence of surface energy. Theexact nature of the bonding depends on the details of the speciesinvolved, but the adsorption process is generally classified asphysisorption (characteristic of weak van der Waals forces)) orchemisorption (characteristic of covalent bonding). It may also occurdue to electrostatic attraction.

“Ash” refers to the residue remaining after complete combustion of thecoal particles. Ash typically includes mineral matter (silica, alumina,iron oxide, etc.).

“At least one”, “one or more”, and “and/or” are open-ended expressionsthat are both conjunctive and disjunctive in operation. For example,each of the expressions “at least one of A, B and C”, “at least one ofA, B, or C”, “one or more of A, B, and C”, “one or more of A, B, or C”and “A, B, and/or C” means A alone, B alone, C alone, A and B together,A and C together, B and C together, or A, B and C together. When eachone of A, B, and C in the above expressions refers to an element, suchas X, Y, and Z, or class of elements, such as X₁-X_(n), Y₁-Y_(m), andZ₁-Z_(o), the phrase is intended to refer to a single element selectedfrom X, Y, and Z, a combination of elements selected from the same class(e.g., X₁ and X₂) as well as a combination of elements selected from twoor more classes (e.g., Y₁ and Z_(o)).

“Biomass” refers to biological matter from living or recently livingorganisms. Examples of biomass include, without limitation, wood, waste,(hydrogen) gas, seaweed, algae, and alcohol fuels. Biomass can be plantmatter grown to generate electricity or heat. Biomass also includes,without limitation, plant or animal matter used for production of fibersor chemicals. Biomass further includes, without limitation,biodegradable wastes that can be burnt as fuel but generally excludesorganic materials, such as fossil fuels, which have been transformed bygeologic processes into substances such as coal or petroleum. Industrialbiomass can be grown from numerous types of plants, includingmiscanthus, switchgrass, hemp, corn, poplar, willow, sorghum, sugarcane,and a variety of tree species, ranging from eucalyptus to oil palm (orpalm oil).

“Carbonaceous” refers to a carbon-containing material, particularly amaterial that is substantially rich in carbon.

“Coal” refers to a combustible material formed from prehistoric plantlife. Coal includes, without limitation, peat, lignite, sub-bituminouscoal, bituminous coal, steam coal, anthracite, and graphite. Chemically,coal is a macromolecular network comprised of groups of polynucleararomatic rings, to which are attached subordinate rings connected byoxygen, sulfur, and aliphatic bridges.

A “composition” refers to one or more chemical units composed of one ormore atoms, such as a molecule, polyatomic ion, chemical compound,coordination complex, coordination compound, and the like. As will beappreciated, a composition can be held together by various types ofbonds and/or forces, such as covalent bonds, metallic bonds,coordination bonds, ionic bonds, hydrogen bonds, electrostatic forces(e.g., van der Waal's forces and London's forces), and the like.

“Halogen” refers to an electronegative element of group VIIA of theperiodic table (e.g., fluorine, chlorine, bromine, iodine, astatine,listed in order of their activity with fluorine being the most active ofall chemical elements).

“Halide” refers to a binary compound of the halogens.

“High alkali coals” refer to coals having a total alkali (e.g., calcium)content of at least about 20 wt. % (dry basis of the ash), typicallyexpressed as CaO, while “low alkali coals” refer to coals having a totalalkali content of less than 20 wt. % and more typically less than about15 wt. % alkali (dry basis of the ash), typically expressed as CaO.

“High iron coals” refer to coals having a total iron content of at leastabout 10 wt. % (dry basis of the ash), typically expressed as Fe₂O₃,while “low iron coals” refer to coals having a total iron content ofless than about 10 wt. % (dry basis of the ash), typically expressed asFe₂O₃. As will be appreciated, iron and sulfur are typically present incoal in the form of ferrous or ferric carbonates and/or sulfides, suchas iron pyrite.

“High sulfur coals” refer to coals having a total sulfur content of atleast about 1.5 wt. % (dry basis of the coal) while “medium sulfurcoals” refer to coals having between about 1.5 and 3 wt. % (dry basis ofthe coal) and “low sulfur coals” refer to coals typically having a totalsulfur content of less than about 1.5 wt. % (dry basis of the coal),more typically having a total sulfur content of less than about 1.0 wt.%, and even more typically having a total sulfur content of less thanabout 0.8 wt. % of the coal (dry basis of the coal).

“Ion exchange medium” refers to a medium that is able, under selectedoperating conditions, to exchange ions between two electrolytes orbetween an electrolyte solution and a complex. Examples of ion exchangeresins include solid polymeric or mineralic “ion exchangers”. Otherexemplary ion exchangers include ion exchange resins (functionalizedporous or gel polymers), zeolites, montmorillonite clay, clay, and soilhumus. Ion exchangers are commonly either cation exchangers thatexchange positively charged ions (cations) or anion exchangers thatexchange negatively charged ions (anions). There are also amphotericexchangers that are able to exchange both cations and anionssimultaneously. Ion exchangers can be unselective or have bindingpreferences for certain ions or classes of ions, depending on theirchemical structure. This can be dependent on the size of the ions, theircharge, or their structure. Typical examples of ions that can bind toion exchangers are: H⁺ (proton) and OH⁻ (hydroxide); single-chargedmonoatomic ions like Na⁺, K⁺, and Cl⁻; double-charged monoatomic ionslike Ca²⁺ and Mg²⁺; polyatomic inorganic ions like SO₄ ²⁻ and PO₄ ³⁻;organic bases, usually molecules containing the amino functional group—NR₂H⁺; organic acids often molecules containing —COO⁻ (carboxylic acid)functional groups; and biomolecules that can be ionized: amino acids,peptides, proteins, etc.

Mercury Active Agent refers to an additive that oxidizes elementalmercury and/or catalyzes the formation of diatomic halogens.

Neutron Activation Analysis (“NAA”) refers to a method for determiningthe elemental content of samples by irradiating the sample withneutrons, which create radioactive forms of the elements in the sample.Quantitative determination is achieved by observing the gamma raysemitted from these isotopes.

“Oxidizing agent”, “oxidant” or “oxidizer” refers to an element orcompound that accepts one or more electrons to another species or agentthat is oxidized. In the oxidizing process the oxidizing agent isreduced and the other species which accepts the one or more electrons isoxidized. More specifically, the oxidizer is an electron acceptor, orrecipient, and the reductant is an electron donor or giver.

“Particulate” refers to fine particles, such as fly ash, unburnedcarbon, soot and fine process solids, typically entrained in a gasstream.

The phrase “ppmw X” refers to the parts-per-million, based on weight, ofX alone. It does not include other substances bonded to X.

The phrase “ppmv X” refers to the parts-per-million, based on volume, ofX alone. It does not include other substances bonded to X.

“Separating” and cognates thereof refer to setting apart, keeping apart,sorting, removing from a mixture or combination, or isolating. In thecontext of gas mixtures, separating can be done by many techniques,including electrostatic precipitators, baghouses, scrubbers, and heatexchange surfaces.

A “sorbent” is a material that sorbs another substance; that is, thematerial has the capacity or tendency to take it up by sorption.

“Sorb” and cognates thereof mean to take up a liquid or a gas bysorption.

“Sorption” and cognates thereof refer to adsorption and absorption,while desorption is the reverse of adsorption.

The preceding is a simplified summary of the disclosure to provide anunderstanding of some aspects of the disclosure. This summary is neitheran extensive nor exhaustive overview of the disclosure and its variousaspects, embodiments, and configurations. It is intended neither toidentify key or critical elements of the disclosure nor to delineate thescope of the disclosure but to present selected concepts of thedisclosure in a simplified form as an introduction to the more detaileddescription presented below. As will be appreciated, other aspects,embodiments, and configurations of the disclosure are possibleutilizing, alone or in combination, one or more of the features setforth above or described in detail below.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings are incorporated into and form a part of thespecification to illustrate several examples of the present disclosure.These drawings, together with the description, explain the principles ofthe disclosure. The drawings simply illustrate preferred and alternativeexamples of how the disclosure can be made and used and are not to beconstrued as limiting the disclosure to only the illustrated anddescribed examples. Further features and advantages will become apparentfrom the following, more detailed, description of the various aspects,embodiments, and configurations of the disclosure, as illustrated by thedrawings referenced below.

FIG. 1 is a block diagram according to an embodiment;

FIG. 2 is a block diagram according to an embodiment;

FIG. 3 is a block diagram according to an embodiment;

FIG. 4 is a block diagram according to an embodiment;

FIG. 5 is a block diagram according to an embodiment;

FIG. 6 is a block diagram according to an embodiment;

FIG. 7 is a plot of total mercury emissions (μg/wscm) (vertical axis)against time (horizontal axis);

FIG. 8 is a block diagram according to an embodiment;

FIG. 9 is a block diagram according to an embodiment;

FIG. 10 is a block diagram according to an embodiment;

FIG. 11 is a block diagram according to an embodiment; and

FIG. 12 is a block diagram according to an embodiment.

DETAILED DESCRIPTION Mercury Removal by Iodine-Containing Additive

The current disclosure is directed to the use of an iodine-containingadditive, typically present in relatively low concentrations, to controlmercury emissions from vapor phase mercury evolving facilities, such assmelters, autoclaves, roasters, steel foundries, steel mills, cementkilns, power plants, waste incinerators, boilers, and othermercury-contaminated gas stream producing industrial facilities.Although the mercury is typically evolved by combustion, it may beevolved by other oxidation and/or reducing reactions, such as roasting,autoclaving, and other thermal processes that expose mercury containingmaterials to elevated temperatures.

There are a number of possible mechanisms for mercury capture in thepresence of iodine.

While not wishing to be bound by any theory, a path for oxidation ofmercury appears to be initiated by one or more reactions of elementalmercury and an iodine molecule in the form of I₂. The oxidationreactions may be homogeneous, heterogeneous, or a combination thereof.For heterogeneous reactions, the reaction or collection surface can, forexample, be an air preheater surface, duct internal surface, anelectrostatic precipitator plate, an alkaline spray droplet, dry alkalisorbent particles, a baghouse filter, an entrained particle, fly ash,carbon particle, or other available surface. It is believed that iodinecan oxidize typically at least most, even more typically at least about75%, and even more typically at least about 90% of the elemental mercuryin the mercury-containing gas stream.

Under most flue gas conditions, the mercury reaction kinetics for iodineappear to be faster at higher temperatures than mercury reactionkinetics for chlorine or bromine at the same temperature. With chlorine,almost all the chlorine in the flame is found as HCl, with very littleCl. With bromine, there are, at high temperatures, approximately equalamounts of HBr on the one hand and Bra on the other. This is believed tobe why oxidation of Hg by bromine is more efficient than oxidation bychlorine. Chemical modeling of equilibrium iodine speciation in asubbituminous flue gas indicates that, at high temperatures, there canbe one thousand times less HI than I (in the form of I₂) in the gas. Inmany applications, the molecular ratio, in the gas phase of amercury-containing gas stream, of elemental iodine to hydrogen-iodinespecies (such as HI) is typically at least about 10:1, even moretypically at least about 25:1, even more typically at least about 100:1,and even more typically at least about 250:1.

While not wishing to be bound by any theory, the end product of reactioncan be mercuric iodide (HgI₂ or Hg₂I₂), which has a higher condensationtemperature (and boiling point) than both mercuric bromide (HgBr₂ orHg₂Br₂) and mercuric chloride (HgCI₂ or Hg₂Cl₂). The condensationtemperature (or boiling point) of mercuric iodide (depending on theform) is in the range from about 353 to about 357° C. compared to about322° C. for mercuric bromide and about 304° C. for mercuric chloride.The condensation temperature (or boiling point) for iodine (I₂) is about184° C. while that for bromine (Br₂) is about 58° C.

While not wishing to be bound by any theory, another possible reactionpath is that other mercury compounds are formed by multi-step reactionswith iodine as an intermediate. One possible multi-step reaction is thatiodine reacts with sulfur oxides to form reduced forms of sulfur, whichreduced forms of sulfur then react with mercury and form capturableparticulate mercury-sulfur compounds.

As will be appreciated, these theories may not prove to be correct. Asfurther experimental work is performed, the theories may be refinedand/or other theories developed. Accordingly, these theories are not tobe read as limiting the scope or breadth of this disclosure.

FIG. 1 depicts a contaminated gas stream treatment process for anindustrial facility according to an embodiment. Referring to FIG. 1, amercury-containing feed material 100 is provided. In one application,the feed material 100 is combustible and can be any synthetic ornatural, mercury-containing, combustible, and carbon-containingmaterial, including coal and biomass. The feed material 100 can be ahigh alkali or high iron coal. In other applications, the presentdisclosure is applicable to noncombustible, mercury-containing feedmaterials, including without limitation metal-containing ores,concentrates, and tailings.

The feed material 100 can natively include, without limitation, varyinglevels of halogens and mercury. Typically, the feed material 100includes typically at least about 0.001 ppmw, even more typically fromabout 0.003 to about 100 ppmw, and even more typically from about 0.003to about 10 ppmw mercury (both elemental and speciated) (measured byneutron activation analysis (“NAA”)). Commonly, a combustible feedmaterial 100 includes no more than about 5 ppmw iodine, more commonly nomore than about 4 ppmw iodine, even more commonly no more than about 3ppmw iodine, even more commonly no more than about 2 ppmw iodine andeven more commonly no more than about 1 ppmw iodine (measured by neutronactivation analysis (“NAA”)). A combustible feed material 100 generallywill produce, upon combustion, an unburned carbon (“UBC”) content offrom about 0.1 to about 30% by weight and even more generally from about0.5 to about 20% by weight.

The feed material 100 is combusted in thermal unit 104 to produce amercury-containing gas stream 108. The thermal unit 104 can be anycombusting device, including, without limitation, a dry or wet bottomfurnace (e.g., a blast furnace, puddling furnace, reverberatory furnace,Bessemer converter, open hearth furnace, basic oxygen furnace, cyclonefurnace, stoker boiler, cupola furnace and other types of furnaces),boiler, incinerator (e.g., moving grate, fixed grate, rotary-kiln, orfluidized or fixed bed, incinerators), calciners including multi-hearth,suspension or fluidized bed roasters, intermittent or continuous kiln(e.g., ceramic kiln, intermittent or continuous wood-drying kiln,anagama kiln, bottle kiln, rotary kiln, catenary arch kiln, Feller kiln,noborigama kiln, or top hat kiln), oven, or other heat generation unitsand reactors.

The mercury-containing gas stream 108 includes not only elemental and/orspeciated mercury but also a variety of other materials. A commonmercury-containing gas stream 108 includes at least about 0.001 ppmw,even more commonly at least about 0.003 ppmw, and even more commonlyfrom about 0.005 to about 0.02 ppmw mercury (both elemental andspeciated). Other materials in the mercury-containing gas stream 108 caninclude, without limitation, particulates (such as fly ash), sulfuroxides, nitrogen oxides, carbon oxides, unburned carbon, and other typesof particulates.

The temperature of the mercury-containing gas stream 108 variesdepending on the type of thermal unit 104 employed. Commonly, themercury-containing gas stream temperature is at least about 125° C.,even more commonly is at least about 325° C., and even more commonlyranges from about 325 to about 500° C.

The mercury-containing gas stream 108 is optionally passed through thepreheater 112 to transfer some of the thermal energy of themercury-containing gas stream 108 to air input to the thermal unit 104.The heat transfer produces a common temperature drop in themercury-containing gas stream 108 of from about 50 to about 300° C. toproduce a mercury-containing gas stream 116 temperature commonly rangingfrom about 100 to about 400° C.

The mercury-containing gas stream 116 is next subjected to particulateremoval device 120 to remove most of the particulates from themercury-containing gas stream and form a treated gas stream 124. Theparticulate removal device 120 can be any suitable device, including anelectrostatic precipitator, particulate filter such as a baghouse, wetparticulate scrubber, and other types of particulate removal devices.

The treated gas stream 124 is emitted, via gas discharge 128, into theenvironment. To control mercury emissions in the mercury-containing gasstream 108, an iodine-containing additive 132 is employed. The iodine inthe additive 132 can be in the form of a solid, liquid, vapor, or acombination thereof. It can be in the form of elemental iodine (I₂), ahalide (e.g., binary halides, oxo halides, hydroxo halides, and othercomplex halides), an inter-halogen cation or anion, iodic acid, periodicacid, periodates, a homoatomic polyanion, and mixtures thereof. In oneformulation, the iodine in the additive 132 is composed primarily of analkali or alkaline earth metal iodide. In one formulation, theiodine-containing additive 132 is substantially free of other halogensand even more typically contains no more than about 25%, even moretypically no more than about 10%, and even more typically no more thanabout 5% of the halogens as halogen(s) other than iodine. In oneformulation, the iodine-containing additive 132 contains at least about100 ppmw, more commonly at least about 1,000 ppmw, and even morecommonly at least about 1 wt. % iodine. In one formulation, theiodine-containing additive contains no more than about 40 wt. % fixed ortotal carbon, more commonly no more than about 25 wt. % fixed or totalcarbon, even more commonly no more than about 15 wt. % fixed or totalcarbon, and even more commonly no more than about 5 wt. % fixed or totalcarbon. In one formulation, the iodine-containing additive 132 is a high(native) iodine coal. In one formulation, the iodine-containing additive132 is an iodine-containing waste or byproduct material, such as amedical waste. In one formulation, the iodine-containing additive 132comprises iodine attached to a solid support, such as by absorption,adsorption, ion exchange, formation of a chemical composition,precipitation, physical entrapment, or other attachment mechanism. Thesolid support can be inorganic or organic. Examples include ion exchangeresins (functionalized porous or gel polymers), soil humus, a porouscarbonaceous material, metal oxides (e.g., alumina, silica,silica-alumina, gamma-alumina, activated alumina, acidified alumina, andtitania), metal oxides containing labile metal anions (such as aluminumoxychloride), non-oxide refractories (e.g., titanium nitride, siliconnitride, and silicon carbide), diatomaceous earth, mullite, porouspolymeric materials, crystalline aluminosilicates such as zeolites(synthetic or naturally occurring), amorphous silica-alumina, mineralsand clays (e.g., bentonite, smectite, kaolin, dolomite, montmorillinite,and their derivatives), porous ceramics metal silicate materials andminerals (e.g., one of the phosphate and oxide classes), ferric salts,and fibrous materials (including synthetic (for example, withoutlimitation, polyolefins, polyesters, polyamides, polyacrylates, andcombinations thereof) and natural (such as, without limitation,plant-based fibers, animal-based fibers, inorganic-based fibers,cellulosic, cotton, paper, glass and combinations thereof). Commonly,the halogen-containing additive 232 contains no more than about 10 wt. %iodine, more commonly no more than about 5 wt. % iodine, even morecommonly no more than about 1 wt. % iodine, even more commonly no morethan about 0.5 wt. % iodine, and even more commonly no more than about0.1 wt. % iodine.

The iodine-containing additive 132 can be contacted with themercury-containing gas stream at one or more contact points 136, 140,and 148 (where point 136 can be remote from the location of the thermalunit, including applying the additive to the feed at places such as amine or in transit to the thermal unit location). At point 136, theiodine-containing additive 132 is added directly to the feed material100 upstream of the thermal unit 104. At points 140 and 148, theiodine-containing additive 132 is introduced into the mercury-containinggas stream 108 or 116, such as by injection as a liquid, vapor, or solidpowder. As can be seen from FIG. 1, the additive introduction can bedone upstream or downstream of the (optional) air preheater 112. Theiodine-containing additive can be dissolved in a liquid, commonlyaqueous, in the form of a vapor, in the form of an aerosol, or in theform of a solid or supported on a solid. In one formulation, theiodine-containing additive 132 is introduced as a liquid droplet oraerosol downstream of the thermal unit 104. In this formulation, theiodine is dissolved in a solvent that evaporates, leaving behind solidor liquid particles of the iodine-containing additive 132.

Surprisingly, the iodine-containing additive 132 can allow mercurycapture without a carbon sorbent, native unburned carbon, or ash beingpresent. In contrast to bromine, mercury removal by iodine does notprimarily depend on co-injection of activated carbon sorbents forvapor-phase mercury capture. In one process configuration, themercury-containing gas stream upstream of the particulate removal deviceis substantially free of activated carbon. The iodine-containingadditive 132 can effectively enable or facilitate removal of at leastabout 40%, even more commonly at least about 75%, and even more commonlyat least about 90% of the elemental and speciated mercury in themercury-containing gas stream when the feed material 100, uponcombustion, produces a UBC of no more than about 30% and even morecommonly of no more than about 5%. When a higher UBC level is produced,the iodine-containing additive 132 can remove at least about 40%, evenmore commonly at least about 75%, and even more commonly at least about90% of the elemental and speciated mercury in the mercury-containing gasstream that is not natively removed by the unburned carbon particles.

In one plant configuration, sufficient iodine-containing additive 132 isadded to produce a gas-phase iodine concentration commonly of about 8ppmw basis of the flue gas or less, even more commonly of about 5 ppmwbasis or less, even more commonly of about 3.5 ppmw basis or less, evenmore commonly of about 1.5 ppmw or less, and even more commonly of about0.4 ppmw or less of the mercury-containing gas stream. Stated anotherway, the iodine concentration relative to the weight ofmercury-containing, combustible (e.g., coal) feed (as fed) (whether bydirect application to the combustible feed and/or injection into themercury-containing (e.g., flue) gas) commonly is about 40 ppmw or less,more commonly about 35 ppmw or less, even more commonly about 30 ppmw orless, even more commonly is about 15 ppmw or less, even more commonly nomore than about 10 ppmw, even more commonly no more than about 6 ppmw,even more commonly about 4 ppmw or less, and even more commonly no morethan about 3 ppmw. Stated another way, the molar ratio, in themercury-containing (e.g., flue) gas, of gas-phase diatomic iodine tototal gas-phase mercury (both speciated and elemental) is commonly nomore than about 1,200, and even more commonly no more than about 600,even more commonly no more than about 250, even more commonly no morethan about 150, and even more commonly no more than about 80. By way ofillustration, an effective concentration of gas-phase iodine at the airpreheater outlet or particulate removal device inlet ranges from about0.1 to about 10 ppmw, even more commonly from about 0.15 to about 5ppmw, even more commonly from about 0.20 to about 2 ppmw, and even morecommonly from about 0.25 to about 1.50 ppmw of the mercury-containinggas stream.

Commonly, the mercury-containing gas stream includes no more than about1.0, even more commonly no more than about 0.5 and even more commonly nomore than about 0.1 ppmw total bromine. The feed material generallyincludes no more than about 10 ppmw and even more commonly no more thanabout 5 ppmw natively occurring bromine.

The mercury-containing (e.g., flue) gas temperature for elementalmercury capture promoted by iodine commonly ranges from about 150 toabout 600° C. and even more commonly from about 180 to about 450° C. Theresidence time upstream of particulate (e.g., fly ash) removal device120 is commonly about 8 seconds, and even more commonly at least about 4seconds, and even more commonly at least about 2 seconds.

Generally, sufficient iodine-containing additive 132 is added to producea gas-phase iodine concentration commonly of about 3.5 ppmw or less,even more commonly of about 2 ppmw or less, even more commonly of about1.5 ppmw or less, and even more commonly of about 0.4 ppmw or less.Stated another way, the molar ratio, in the mercury-containing (e.g.,flue) gas, of gas-phase iodine to total gas-phase mercury (bothspeciated and elemental) is commonly no more than about 1,000, even morecommonly no more than about 600, even more commonly no more than about500, even more commonly no more than about 250, even more commonly nomore than about 150, and even more commonly no more than about 80.

The above concentration ranges and conditions can, in appropriateapplications, apply to bromine as a mercury removal additive.

Mercury Removal by Halogen-Containing Additive in Presence of SelectiveCatalytic Reduction

In another plant configuration shown in FIG. 2, the halogenconcentration needed to effect mercury removal is further reduced bycoupling halogen with a selective catalytic reduction (“SCR”) zone priorto particulate removal. As will be appreciated, SCR converts nitrogenoxides, or NO_(x), with the aid of a catalyst, into diatomic nitrogen(N₂) and water. A gaseous reductant, typically anhydrous ammonia,aqueous ammonia, or urea (but other gas-phase reductants may beemployed), can be injected into a stream of flue or exhaust gas or othertype of gas stream or absorbed onto a catalyst followed by off gassingof the ammonia into the gas stream. Suitable catalysts include, withoutlimitation, ceramic materials used as a carrier, such as titanium oxide,and active catalytic components, such as oxides of base metals (such asvanadium (V₂O₅), wolfram (WO₃), titanium oxide (TiO₂) and tungstate(e.g., WO₄ ²⁻), zeolites, and various precious metals. Other catalysts,however, may be used.

The SCR catalyst surface, depending on the design, catalyst andlayering, is active for reactions other than the primary nitrogen oxidereduction. There are competing reactions occurring for available sitesto reduce NOx, oxidize SO₂ to SO₃ and to promote the reaction of mercurywith various species to result in an increased fraction of oxidizedmercury species. The SCR ammonia rate is co-variable with load andtemperature and affects the balance between these competing reactions.

The presence of ultra trace vapor iodine and/or bromine species at theSCR catalyst surface can be surprisingly effective for mercury control.While not wishing to be bound by any theory, the amount of halogen(e.g., iodine and/or bromine) required to result in the formation of anoxidized form of mercury is lower when an SCR is in use. The surface ofthe SCR catalyst is believed to promote the formation of diatomicelemental halogens and/or mercury oxidation.

To capture the oxidized mercury in the particulate collection device,vapor SO₃ in the flue gas should be managed to limit the concentrationafter the air preheater. This can be accomplished by selection oflower-sulfur and higher alkaline coal, selection of lower activity SCRcatalyst and control of SCR reagent injection rate and temperature.These interactive parameters must be managed to achieve the desireddeNOx rate.

In one configuration, combustion of high alkali coals and low-sulfurcoals is preferred to further inhibit formation of vapor SO₃ species.The SCR catalyst is typically selected to yield a specified SO₂ to SO₃conversion rate for a design coal and operating condition. Catalystactivity gradually degrades over a period of years and must be replaced.A number of catalytic layers installed at intervals, with differentoxidation rates, ages and catalyst activity are typically present forcoal-fired plant SCRs. Effective SO₂ to SO₃ oxidation rate across theaggregate of catalyst surfaces in an SCR should be preferably lower thanabout 2.0% and more preferably lower than about 1.5% and even morepreferably lower than about 1.2% in order to limit vapor SO₃ formationin the SCR.

Vapor SO₃ can also be controlled after formation in the SCR by means ofin-duct injection of sorbents or by absorption in a dry scrubber. VaporSO₃ can also be condensed on intermediate surfaces prior to theparticulate control device, in particular the air preheater. Lowerprocess temperatures will reduce SCR oxidation rate and increase SO₃dropout in the air preheater. Mercury oxidation in the SCR benefits whenSO₃ is reduced as a competing reaction, even at lower temperatures.

Ammonia reacts within the SCR to reduce nitrogen oxides. Excess ammonialowers the ability of the SCR to react with or catalyze reaction(oxidation) of mercury. In one configuration, concentration(s) ofammonia and precursors thereof are maintained at a level just sufficientfor deNOx. That is, the concentration of ammonia and precursors thereofis preferably no more than about 125%, more preferably no more thanabout 120%, more preferably no more than about 115%, and even morepreferably no more than about 110% of the stoichiometric amount requiredto perform deNOx. As a result, the amount of ammonia slip will bereduced relative to conventional SCR-based systems. SCR reagent rateand/or ammonia and precursor addition is controlled to yield an averageflue gas ammonia slip immediately downstream of the SCR of preferablyless than about 5 ppmv and more preferably less than about 3 ppmv asammonia.

To realize the full benefits of mercury oxidation by low concentrationhalogen addition with SCR and further achieve substantial removal ofmercury in the particulate control device, the vapor SO₃ in the flue gasat the particulate control device inlet is commonly limited to less thanabout 7.5 ppmv, more commonly to less than about 5 ppmv and morepreferably to less than 2 ppmv at all process conditions by the methodsdescribed above, singly or in combination.

In one configuration, the halogen/mercury mass ratio for iodine as theprimary halogen additive is commonly no more than about 200, morecommonly no more than about 100, more commonly no more than about 75,more commonly no more than about 50, and more commonly no more thanabout 40 and commonly at least about 5, more commonly at least about 10,more commonly at least about 15, and even more commonly at least about20.

In one configuration, the halogen/mercury mass ratio for brome as theprimary halogen additive is commonly no more than about 400, morecommonly no more than about 300, more commonly no more than about 275,more commonly no more than about 250, and more commonly no more thanabout 240 and commonly at least about 10, more commonly at least about20, more commonly at least about 30, and even more commonly at leastabout 40.

In one configuration, the maximum amount of halogen added to the feedmaterial 100 is commonly no more than about 40 ppmw, more commonly nomore than about 25 ppmw, more commonly no more than about 20 ppmw, morecommonly no more than about 15 ppmw, and even more commonly no more thanabout 10 ppmw, and the minimum amount of halogen added to the feedmaterial 100 is commonly at least about 0.5 ppmw, more commonly at leastabout 0.75 ppmw, more commonly at least about 1 ppmw, and even morecommonly at least about 1.5 ppmw.

The embodiment is directed particularly to the capture of mercury fromsystems with conventional SCR firing low sulfur and halogen-deficientcoals (e.g., coals having no more than about 6 ppmw bromine and/oriodine). The embodiment can enhance mercury capture on the particulatecontrol device and not on any wet flue gas desulfurization (FGD)scrubber. Low concentration iodine, in particular, surprisingly achievesmercury oxidation with SCR, and the oxidized mercury can be captured inthe particulate-phase on the fly ash surface, particularly when thesulfur trioxide concentration in the flue gas at the particulate controldevice is managed to an amount of less than about 2 ppmv. Thisembodiment can be used with currently installed SCR catalysts for lowsulfur, low halogen fueled units. In addition, though for bituminouscoals there is ample native chlorine and bromine to oxidize mercury toas high as 100% across the SCR, the SCR is generally unable to realizeany mercury capture until the FGD scrubber (due to the vapor SO₃).Iodine-oxidized mercury species are typically not effectively capturedin an FGD scrubber because iodine-Hg species are generally not soluble.Accordingly, the present embodiment captures mercury (for lower SO₃concentrations) at the ESP or baghouse.

Referring to FIG. 2, the waste stream 108 optionally flows through aneconomizer 200, which transfers some of the heat of the combustionstream 108 to water for recycle to other operations. Thehalogen-containing additive 232 is contacted with the feed material 100upstream of the thermal unit 104 and/or with the mercury-containing gasstream 108 inside or downstream of the thermal unit 104.

The mercury-containing gas stream 108 proceeds to SCR unit 204, wherenitrogen oxides are converted into molecular nitrogen and water.

The mercury-containing gas stream 108 proceeds to the optional airpreheater 112 and then is subjected to particulate removal byparticulate removal device 120 to form a treated gas stream 124 that issubstantially free of particulates and mercury. As will be appreciated,an economizer uses waste heat by transferring heat from flue gases towarm incoming feedwater (e.g., which is subsequently converted intosteam for power generation) while a preheater is a heat exchanger thattransfers thermal energy from flue gas to combustion air before input ofthe combustion air to the furnace.

The treated gas stream 124 is then emitted from the gas discharge 128.

Although the SCR catalyst is commonly located between the economizer andair preheater outlet, it may be located at other locations in themercury-containing gas stream. The SCR catalyst is commonly locatedprior to (or upstream of) the particulate removal device (e.g. baghouseand electrostatic precipitator). Commonly, SCR catalysis is performed ata temperature ranging from about 250 to about 500° C., more commonly ata temperature ranging from about 300 to about 450° C., and even morecommonly at a temperature ranging from about 325 to about 400° C. Thedegree of SO₂ to SO₃ oxidation by the SCR varies within this temperaturerange depending on plant load, catalyst characteristics and otherprocess conditions. At lower temperatures, the SCR contribution to totalvapor SO₃ can be negligible.

Removal of Mercury by Halogen-Containing Additive and Mercury ActiveAgent

In another configuration, a combination of iodine or bromine on the onehand with another mercury active agent on the other is utilized toeffect mercury oxidation and removal, particularly at highertemperatures than is possible with bromine or chlorine or hydrogenchloride alone. As used herein, a “mercury active agent” refers to anadditive that oxidizes elemental mercury and/or catalyzes the formationof diatomic halogens. Conversion of elemental mercury to oxidizedspecies is typically accomplished by the combined halogens that areeither present in or added to the combustible fuel.

In one plant design, additional halogens, preferably in the form ofdiatomic elemental halogens, are, in addition to those in thecombustible fuel, injected post-combustion.

In another plant design, oxidants, such as other halogens or non-halogenmercury active agents, are added to the combustible fuel in addition toor in lieu of downstream flue gas introduction.

Examples of suitable mercury active agents that are oxidants, which arecombined with iodine or bromine prior to fuel pre-combustion includebromide salts including sodium, calcium, magnesium, zinc or potassiumbromide, calcium, sodium or potassium bromate, iodide salts includingsodium, calcium, magnesium, zinc or potassium iodide, calcium, sodium orpotassium iodate, chloride salts including sodium, calcium, magnesium,zinc or potassium chloride, calcium, sodium or potassium chlorate,sodium, iron oxides sufficient to enrich the fly ash, and diatomicbromine or chlorine sorbed onto a suitable sorbent.

Examples of additional mercury active agents that are oxidants added tothe feed material pre- or to the waste gas post-combustion incombination with iodine or bromine added to the feed material includebromine, iodine, or chlorine gas (preferably as diatomic elementalhalogens), hydrogen bromide, hydrogen chloride, chlorite, chlorate,perchlorate, hypochlorite, and other bromine, chlorine andfluorine-containing compounds, finely divided iron oxides, copper oxidesand other base metal oxides.

As will be appreciated, other mercury active agents can be employed. Forexample, different mercury active agents, that perform differing of thefunctions of oxidizing elemental mercury and/or catalyzing the formationof diatomic halogens, can be blended, mixed or otherwise combined orco-injected. For example, mercury oxidants can be added upstream, in, ordownstream of the SCR zone. In one formulation, a first mercury activeagent, such as an SCR catalyst, can catalyze the formation of diatomichalogens, a second mercury active agent, such as a halogen-containingcompound or metal oxide, can oxidize elemental mercury and a reactivesurface agent, such as circulating fluidized bed ash, powdered zeolites,fluidized catalytic cracker (FCC) fines, fumed silicates, metal oxideparticles or powders, such as iron oxide, re-milled or fine fraction flyash, fluidized bed combustor ash and combinations thereof, providessurface area for removal of mercury compounds.

While not wishing to be bound by any theory, it is believed that thehalogen in the form of diatomic halogen gas is both an efficient mercuryoxidizer and is available for reaction with oxidized mercury by directhalogenation to form, for example, HgI₂ or HgBr₂. In this configuration,the iodine (or iodine and bromine or bromine) concentration needed toeffect mercury oxidation and mercury halogenation is reduced by additionof an oxidant to the flue or waste gas.

The mercury active agent and halogen are believed to act synergisticallyto effect mercury oxidation for subsequent removal by fly ash, unburnedcarbon, or another suitable additive. The mercury active agent can besupported or unsupported, with preferred carriers being a porouscarbonaceous substrate (such as fly or bottom ash from coal combustion,carbon black, activated carbon, coke, char, charcoal, and the like),activated alumina, ceramic, clay, silica, silica-alumina, silicates,zeolites, fine fraction fly ash, bottom ash, FCC fines, fluidized bedcombustor ash, and the like. The mercury active agent can be introducedeither as a liquid, such as a slurry in a vaporizable carrier liquid ordissolved in a solvent, as particles or powders, as a gas, or as acombination thereof.

In either of the above plant configurations, the mercury oxidation,whether by unburned carbon or mercury active agent addition, isperformed preferably between the economizer and air preheater outlet orat a preferred temperature of from about 250 to about 500° C., a morepreferred temperature of from about 300 to about 450° C., and an evenmore preferred temperature of from about 325 to about 400° C.

In one application, iodine and/or bromine is added to the combustiblefuel or otherwise introduced to the furnace or boiler, such as in levelsset forth above, while a diatomic elemental halogen (such as diatomicelemental iodine, bromine, and/or chlorine) is added to the flue gasdownstream from the furnace or boiler. In this configuration, the fluegas concentration of the injected or otherwise introduced diatomicelemental halogen preferably ranges from about 0.1 to about 8 ppm_(w) ofthe flue gas, even more preferably from about 0.25 to about 5 ppm_(w),and even more preferably from about 0.5 to about 2 ppm_(w).

In one application, iodine and/or bromine are added to the combustiblefuel or otherwise introduced to the furnace or boiler while anon-halogen oxidant, such as those set forth above, is added to the fluegas downstream from the furnace or boiler. In this configuration, theflue gas concentration of the injected or otherwise introduced oxidantpreferably ranges from about 0.1 to about 8 ppm_(w), even morepreferably from about 0.25 to about 5 ppm_(w), and even more preferablyfrom about 0.5 to about 2 ppm_(w).

In either application, the halogen or non-halogen oxidant or mixturethereof is typically introduced either as a gas or a liquid droplet oraerosol, with the oxidant being dissolved in a vaporizable solvent.

In one application, halide or interhalogen compound-containing additive132 is added to the feed material 100 or otherwise introduced to thethermal unit 104 while diatomic elemental iodine (I₂) or bromine (Br₂)is added to the flue gas downstream from the thermal unit 104. In thisconfiguration, the flue gas concentration of the injected or otherwiseintroduced diatomic iodine commonly ranges from about 0.1 to about 8ppmw, even more commonly from about 0.25 to about 5 ppmw, and even morecommonly from about 0.5 to about 2 ppmw of the mercury-containing gasstream.

FIGS. 8-9 provide an example of a plant configuration according to anembodiment.

The mercury active agent 900 is introduced to the feed material 100, inthe thermal unit 104, at a point 140 between the thermal unit 104 andoptional preheater 112 and/or at a point 148 between the optionalpreheater 112 and a particulate removal device 120 or between theoptional preheater 112 (FIG. 8) and a scrubber 400 (FIG. 9). When themercury active agent 900 is introduced upstream of the preheater 112,the mercury active agent 900 is typically a non-carbonaceous agent dueto the high mercury-containing gas stream temperature.

The mercury-containing gas stream 116 is thereafter treated by theparticulate removal device 120 (FIG. 8) and/or by the dry scrubber 400and particulate removal device 120 (FIG. 9) to form a treated gasstream. The dry scrubber 400 injects a dry reagent or slurry into themercury-containing gas stream 116 to “wash out” acid gases (such as SO₂and HCl). A dry or semi-dry scrubbing system, unlike a wet scrubber,does not saturate the flue gas stream that is being treated withmoisture. In some cases, no moisture is added. In other cases, only theamount of moisture that can be evaporated in the flue gas withoutcondensing is added.

Although the scrubber 400 is shown after the preheater 112, it is to beunderstood that the scrubber 400 may be located at several differentlocations, including without limitation in the thermal unit 104 or inthe gas stream duct (at a point upstream of the particulate controldevice 120 such as at points 140 and/or 148) (as shown in FIG. 9).

The particulate control device 120 removes substantially all andtypically at least about 90% of the particles entrained in themercury-containing gas stream 116. As a result, at least most of theiodine and mercury in the mercury-containing gas stream 116 is removedby the particle removal device 120.

Removal of Mercury by Halogen-Containing Additive and Reactive SurfaceAgent Addition

Although additional reactive surface particles are normally not requiredfor iodine to form a mercury-containing particulate, in otherembodiments addition of carbon- and non-carbon-containing solid and/oraerosol particles, referred to as “reactive surface agents”, infavorable regions of the flue gas stream can enhance mercury removal bythe iodine-containing additive 132, particularly when the feed material100 produces, upon combustion, a low UBC level or the mercury-containinggas stream 108 has low levels of natively occurring particulates, suchas ash, unburned carbon, soot, and other types of particulates. Low UBClevels generally comprise no more than about 30, even more generally nomore than about 5, and even more generally no more than about 0.5% UBCin the post-combustion particulate. In one configuration, the surfaceactive agent acts as a support for iodine or bromine, as discussedabove.

While not wishing to be bound by any theory, it is believed thatreactive surface agents provide surface area that iodine, mercury,and/or mercuric iodide or bromide can chemically react with (e.g.,provides surface area for heterogeneous mercury reactions) and/orotherwise attach to. The reactive surface agent can be any carbon- ornon-carbon-containing particle that provides a nucleation or reactionsite for iodine, bromide, mercury, mercuric iodide, and/or mercuricbromide. Suitable solid or liquid reactive surface agents 300 include,without limitation, zeolites, silica, silica alumina, alumina,gamma-alumina, activated alumina, acidified alumina, amorphous orcrystalline aluminosilicates, amorphous silica alumina, ion exchangeresins, clays (such as bentonite), a transition metal sulfate, porousceramics, porous carbonaceous materials, such as coal ash (e.g., fly orbottom ash), unburned carbon, charcoal, char, coke, carbon black,activated carbon, other hydrocarbon and coal derivatives, and otherforms of carbon, trona, alkali metal bicarbonates, alkali metalbisulfates, alkali metal bisulfites, alkali metal sulfides, elementalsulfur, limestone, hydrated or slaked lime, circulating fluidized bedash, fluidized catalytic cracker (FCC) fines, fumed silicates, metaloxide particles or powders, such as iron oxide and those comprisinglabile anions, re-milled or fine fraction fly ash, bottom ash, fluidizedbed combustor ash, and mixtures thereof. The reactive surface agent 300may be introduced as a solid particle (powder) and/or as a dissolved orslurried liquid composition comprising a vaporizable liquid carrier.

The mean, median, and P₉₀ sizes of the particles are typically no morethan about 100 microns, even more typically no more than about 50microns, even more typically no more than about 25 microns, even moretypically no more than about 10 microns, and even more typically no morethan about 5 microns. Unlike iodine additives, micron-sized non-carbonparticles have not been consistently effective with bromine orchlorine-based coal additives.

In some configurations, the reactive surface agent is a porouscarbonaceous or non-carbonaceous material, such as coke, fly ash, bottomash, pet coke, carbon black, activated carbon, charcoal, char,beneficiated unburned carbon derived from fly ash, and mixtures thereof.In some applications, the porous carbonaceous or non-carbonaceousmaterial is powdered and typically has a P₈₅ size of no more than about1 mm in size and more typically of no more than about 0.75 mm in sizeand an average diameter typically between about 0.10 to about 0.75 andmore typically between about 0.15 to about 0.25 mm. In someapplications, the porous carbonaceous or non-carbonaceous material isgranular and typically has a P₈₅ size of more than about 1 mm in sizeand more typically of in the range of from about 1 mm to about 2.5 mm insize and an average diameter typically between about 0.75 to about 1.25mm.

The porous carbonaceous or non-carbonaceous material may be impregnatedwith a chemical agent, such as a mercury active agent. Porouscarbonaceous or non-carbonaceous materials can contain a variety ofinorganic impregnants, such as ionic, elemental, or compounded halogens(e.g., iodine, iodide, bromine, bromide, chlorine, chloride,iodine-containing salts, bromine-containing salts, chlorine-containingsalts, and mixtures thereof) silver, and cations such as alkali earthmetals, alkaline earth metals, and transition metals. In oneformulation, the porous carbonaceous or non-carbonaceous material isimpregnated with a mercury active agent or SCR catalytic material.

The amount of chemical agent in the porous carbonaceous ornon-carbonaceous material can vary widely. Commonly, the impregnatedporous carbonaceous or non-carbonaceous material comprises at leastabout 0.1 wt. %, more commonly at least about 0.5 wt. %, and even morecommonly at least about 1 wt. % chemical agent and no more than about 5wt. %, more commonly no more than about 4 wt. %, and even more commonlyno more than about 2 wt. % chemical agent.

The porous carbonaceous material or non-carbonaceous can have a highsurface area. Typically, the porous carbonaceous or non-carbonaceousmaterial has a surface area of at least about 500 m²/g, more typicallyof at least about 750 m²/g, and even more typically of at least about1,000 m²/g and no more than about 2,500 m²/g, more typically no morethan about 2,000 m²/g, and even more typically no more than about 1,500m²/g.

The ash content of the porous carbonaceous or non-carbonaceous materialcan determine the efficiency of reactivation. The porous carbonaceous ornon-carbonaceous material typically has an ash content in the range offrom about 10% to about 95% and even more typically in the range of fromabout 20% to about 70%.

Commonly, the reactive surface agent is introduced downstream of theiodine-containing additive 132, more commonly downstream of theeconomizer 200, and more commonly downstream of the air preheater 112and upstream of particulate removal device 120 and/or scrubber 400.

In other embodiments, the additive 132 is combined with other pollutioncontrol technologies that provide suspended solid and/or aerosolparticles or other reaction surfaces at favorable location andtemperature. Exemplary embodiments include, without limitation:

1. Spraying slurried solids or solutions of dissolved solids at a pointupstream to allow sufficient evaporation. In a utility boiler, thisregion would normally be prior to, or upstream of, any air preheater 112to allow sufficient residence time.

2. Providing a downstream slurry spray such as by conventional flue gasdesulfurization (“FGD”) spray dryer absorber (“SDA”). The slurry spraywould normally downstream of any air preheater 112.

3. Providing alkaline liquid spray, such as wet FGD, to capture residualmercury past the ESP rather than allowing re-emission of mercury aselemental mercury—as can happen with bromine or chlorine.

4. Providing intimate particulate contact for the iodine-mercury orbromine-mercury compounds, such as filtering the flue gas through afabric filter.

5. Providing additional submicron aerosol at the inlet to an airpreheater 112 to take advantage of the temperature differential acrossthe air preheater to boost surface reaction.

Examples of these alternatives will be discussed with reference to FIGS.3-6 and 8.

Referring to the embodiments of FIGS. 3 and 4, the reactive surfaceagent 300 is introduced at a point 140 between the thermal unit 104 andoptional preheater 112 and/or at a point 148 between the optionalpreheater 112 and a particulate removal device 120 (FIG. 3) or betweenthe optional preheater 112 and a scrubber 400 (FIG. 4). When thereactive surface agent 300 is introduced upstream of the preheater 112and vapor phase halogens are present in the gas stream, the reactivesurface agent 300 is believed to increase the maximum temperature wheremercury removal begins and increase the overall mercury removaleffectiveness.

The mercury-containing gas stream 116 is thereafter treated by theparticulate removal device 120 (FIG. 3) and/or by the dry scrubber 400and particulate removal device 120 (FIG. 4) to form a treated gasstream.

Although the scrubber 400 is shown after the preheater 112, it is to beunderstood that the scrubber 400 may be located at several differentlocations, including without limitation in the thermal unit 104 or inthe gas stream duct (at a point upstream of the particulate controldevice 120 such as at points 140 and/or 148) (as shown in FIG. 4).

The particulate control device 120 removes substantially all andtypically at least about 90% of the particles entrained in themercury-containing gas stream 116. As a result, at least most of theiodine and mercury in the mercury-containing gas stream 116 is removedby the particle removal device 120.

In another embodiment shown in FIG. 6, the reactive surface agent 300 isintroduced at one or more points 140, 148, and/or 600 to themercury-containing gas stream. The mercury-containing gas streamtreatment process includes first and second particulate removal devices120A and B positioned on either side or on a common side (e.g.,downstream) of the preheater 112. Due to the higherreaction/condensation temperature of iodine compared to bromine, thehalogen-containing additive 232 can be introduced to the feed material100, in the thermal unit 104, between the thermal unit 104 and firstparticulate removal device 120A and/or between the first and secondparticulate removal devices 120A and B to enable or facilitate removalof a first portion of the evolved elemental and speciated mercury in themercury-containing gas stream 108. The reactive surface agent 300 mayoptionally be introduced between the first and second particulateremoval devices 120A and B to enable or facilitate removal of additionalelemental and speciated mercury in the second particulate removal device120B. The first portion represents typically at least most of themercury in the mercury-containing gas stream 108 upstream of the firstparticulate removal device 120. In one configuration, the reactivesurface agent 300 is typically a non-carbon agent due to the highmercury-containing gas stream temperature upstream of the preheater 112.

FIG. 5 shows a mercury-containing gas stream treatment system accordingto another embodiment.

The treated gas stream 504 is further treated by a scrubber 500 prior todischarge by gas discharge 126 to remove speciated mercury compounds,not removed by the particulate removal device 120, and sulfur oxides.The scrubber 500 is typically a wet scrubber or flue gas desulfurizationscrubber. Wet scrubbing works via the contact of target compounds orparticulate matter with the scrubbing solution. The scrubbing solutioncomprises reagents that specifically target certain compounds, such asacid gases. A typical scrubbing solution is an alkaline slurry oflimestone or slaked lime as sorbents. Sulfur oxides react with thesorbent commonly to form calcium sulfite and calcium sulfate.

The scrubber 500 has a lower dissolved mercury and/or halogenconcentration than conventional treatment systems, leading to lesscorrosion and water quality issues. Although mercury vapor in itselemental form, Hg⁰, is substantially insoluble in the scrubber, manyforms of speciated mercury and halogens are soluble in the scrubber.Diatomic iodine, however, has a very low solubility in water (0.006g/100 ml), which is significantly different from (less soluble than) Cl₂and Br₂.

Because mercuric iodide is significantly less soluble than mercuricchloride or bromide and because a greater fraction of mercury is removedby particulate removal devices (e.g. baghouse and electrostaticprecipitator) prior to the wet scrubber, soluble mercury present in thescrubber slurry will be reduced. As will be appreciated, mercuricchloride and bromide and diatomic chlorine and chloride, due to theirhigh solubilities, will typically build up in the scrubber sludge tohigh levels, thereby requiring the scrubber liquid to be periodicallytreated. In addition, mercury contamination of by-product FGD gypsumboard is a problem that this disclosure also addresses by reducingmercury present in scrubber slurry.

In some applications, the total dissolved mercury concentration in thescrubber is relatively low, thereby simplifying treatment of thescrubber solution and reducing mercury contamination of by-productmaterials. Typically, no more than about 20%, even more typically nomore than about 10%, and even more typically no more than about 5% ofthe total mercury in the mercury-containing gas stream is dissolved inthe scrubber solution.

As set forth below, test data show that the iodine is surprisingly andunexpectedly effective compared to what was previously thoughtachievable from injection of halogens including, bromine or chlorine.Whereas other halogens, such as bromine, generally require additiverates between 30 and 100 ppmw of feed material 100, iodine appears to beat least 10 times more effective. Applicant has measured 70 to 90%mercury capture with just 3 ppmw iodine in the feed material.

A further plant configuration is shown in FIG. 10.

A combustible feed material 100 and halogen-containing additive 232(which may be formed by the process above) are combusted in the thermalunit 104 to produce the mercury-containing gas stream 108. Themercury-containing gas stream 108 is treated by optional (hot-side)particulate removal device 120 to remove at least most of anyparticulate material in the mercury-containing gas stream 108 andproduce a (treated) mercury-containing gas stream 116. Themercury-containing gas stream 116 is passed through optional preheater112 to produce a cooled gas stream 804. The cooled gas stream 804 issubjected to optional (cold-side) particulate removal device 120 toremove at least most of any particulates in the cooled gas stream 804and form the treated gas stream 124.

Porous carbonaceous or non-carbonaceous material 800 is introduced,typically by injection, into the mercury-containing gas stream 108 atone or more contact points 140, 148, and 600. The porous carbonaceous ornon-carbonaceous material 800 collects gaseous contaminants, includingoxidized mercury, speciated mercury, acid gases, and halogens andhalides, prior to be removed by the optional particulate removal device120 and/or 120.

The porous carbonaceous or non-carbonaceous material 800 can beentrained in a carrier gas or in the form of a slurry when introduced,under pressure, into the gas stream. The rate of addition of the porouscarbonaceous or non-carbonaceous material 800 to the gas streamtypically is in the range of from about 6 to about 0.1, more typicallyin the range of from about 4 to about 0.25, and even more typically inthe range of from about 2 to about 0.5 lb material/MMacf gas.

FIG. 11 depicts a process according to another embodiment. In thisembodiment, the unused halogens, particularly bromine, are removedbefore discharge of the flue gas from the stack 1232. In this manner,the deleterious effects of certain halogens on the environment areavoided.

The combustion stream 1208, before or after the air preheater 1220, issubjected to halogen removal by the halogen removal unit 1400 to removeone or more selected halogens and/or halides. In halogen removal,preferably at least most, more preferably at least about 65%, morepreferably at least about 75% and even more preferably at least about85% of the selected gas phase halogens and/or halides are removed fromthe flue gas 1208. The halogen removal unit 1400 can be any suitabledevice, such as a scrubber. Packed bed scrubber (absorber) can be usedfor halogen and halide removal. Packed bed halogen scrubbers can, forexample, use activated alumina or activated charcoal as the scrubbingmedium to remove halogens and halides. Examples of such scrubbersinclude the F5100™, F5200™, and F5300™ series gas scrubbers of SpectraGases Inc. Wet halogen scrubbers rely on the high solubilities ofhalogens and halides in aqueous liquids. Virtually all types of wetscrubbers will perform adequately as long as they are properly designedfor the HCl, HBr, and/or HF concentrations in the gas stream. The mostcommon type of wet scrubber absorber for HCl and/or HF is the packedtower scrubber. Another type of HCl scrubbing system has a venturiscrubber upstream from the packed bed scrubber to remove particulatematter before it can cause partial pluggage at the bed inlet. In wetscrubbers, it is important to maintain the dissolved concentration ofany halogen species below its solubility limit. This can be done byremoving a slip stream of the liquid, which is subjected tohalogen/halide removal, such as by membrane separation, precipitation,adsorption, and/or absorption. In elemental halogens, such as Br2, anoxidant or reductant can be used to ionize the bromine into species thatmay be easier to remove from the scrubbing solution. Halogens andhalides can also be controlled effectively in spray-dryer-type dryscrubbers and/or dry-injection-type dry scrubbers.

Removed halogens 1404 can be regenerated 1420 for recycle to thehalogen-containing additive 1250. Recycle 1420 can require the selectedhalogen or halide to be converted into a selected halogen species, suchas elemental bromine, and/or a specific halogen formulation. Forexample, substantially all of the chlorine and/or fluorine could beremoved from recovered bromine species before the recovered brominespecies are recycled. Other dissolved impurities, such as sulfur oxides,nitrogen oxides, and the like, could be removed before recycle.Selective removal of the various species can be, for example, bymembrane separation, precipitation, adsorption, and/or absorption.

As a result of halogen removal, the flue gas 1428 has a lowconcentration of the target halogen and/or halide. Preferably, theconcentration of the selected gas phase halogens and/or halides in theflue gas 1428 is no more than about 25 ppm, more preferably no more thanabout 20 ppm, more preferably no more than about 15 ppm, more preferablyno more than about 10 ppm, and even more preferably no more than about 5ppm.

FIG. 12 depicts a process according to another embodiment. In thisembodiment, the unused halogens, particularly bromine, are removedbefore discharge of the flue gas from the stack 1232. In this manner,the deleterious effects of certain halogens on the environment areavoided.

The combustion stream 1208, before or after the air preheater 1220, istreated by a dry or wet scrubber 1404 to remove typically at least mostand more typically at least about 75% of any remaining particulates,acid gases, and halogens/halides in a treated gas stream 1408 to form ascrubbed gas stream 1428. The scrubber slurry 1412 is subjected tohalogen removal by the halogen removal unit 1400 to remove one or moreselected halogens and/or halides. In halogen removal, preferably atleast most, more preferably at least about 65%, more preferably at leastabout 75%, and even more preferably at least about 85% of the selectedhalogens and/or halides in the scrubber slurry 1412 are removed from thecombustion stream 208.

The scrubber 1404 can be any suitable device. Packed bed scrubber(absorber) can be used for halogen and halide removal. Packed bedhalogen scrubbers can, for example, use activated alumina or activatedcharcoal as the scrubbing medium to remove halogens and halides and acidgas. Virtually all types of wet scrubbers will perform adequately aslong as they are properly designed for the HCl, HBr, HF, and/or otheracid gas concentrations in the gas stream. The most common type of wetscrubber absorber (or scrubbing medium) for HCl and/or HF is the packedtower scrubber. Another type of HCl scrubbing system has a venturiscrubber upstream from the packed bed scrubber to remove particulatematter before it can cause partial pluggage at the bed inlet. In wetscrubbers, it is important to maintain the dissolved concentration ofany halogen species below its solubility limit. This can be done byremoving a slip stream of the liquid, which is subjected tohalogen/halide removal, such as by membrane separation, precipitation,adsorption, and/or absorption. In elemental halogens, such as Br2, anoxidant or reductant can be used to ionize the bromine into species thatmay be easier to remove from the scrubbing solution. Halogens andhalides can also be controlled effectively in spray-dryer-type dryscrubbers and/or dry-injection-type dry scrubbers.

The aqueous phase halogens and halides are removed from the scrubberslurry 1412 (or scrubber medium) by the halogen removal unit 1400.Dissolved halogens and halides can be removed by any suitable techniqueincluding ion exchange resin, solvent extraction, adsorption,absorption, precipitation, membrane filtration, and the like. In oneconfiguration, the halogens and halides are removed by ion exchange andstripped from the ion exchange medium by a stripping solution. In oneconfiguration, the dissolved halogens and halides are removed in anorganic solvent, such as a hydrocarbon solvent. Removal is effectedbased on the relative solubilities of the halogens and halides in twodifferent immiscible liquids, namely the aqueous phase of the scrubbingsolution and an organic solvent. In other words, the halogen and/orhalide is extracted from one liquid phase into another liquid phase.Extraction can be done by without chemical change, by a solvationmechanism, by an ion exchange mechanism, by ion pair extraction, or byaqueous two-phase extraction. In one configuration, the dissolvedhalogens and halides are removed by adsorption or absorption onto acarbonaceous medium, such as activated carbon, coke, graphite, and thelike.

Removed halogens 1404 can be regenerated 1420 for recycle to thehalogen-containing additive 250. Recycle 1420 can require the selectedhalogen or halide to be converted into a selected halogen species, suchas elemental bromine, and/or a specific halogen formulation. Forexample, substantially all of the chlorine and/or fluorine could beremoved from recovered bromine species before the recovered brominespecies are recycled. Other dissolved impurities, such as sulfur oxides,nitrogen oxides, and the like, could be removed before recycle.Selective removal of the various species can be, for example, bymembrane separation, precipitation, adsorption, and/or absorption.

As a result of halogen removal, the flue gas 1428 has a lowconcentration of the target halogen and/or halide. Preferably, theconcentration of the selected gas phase halogens and/or halides in theflue gas 1428 is no more than about 25 ppm, more preferably no more thanabout 20 ppm, more preferably no more than about 15 ppm, more preferablyno more than about 10 ppm, and even more preferably no more than about 5ppm.

EXPERIMENTAL

The following examples are provided to illustrate certain embodiments ofthe invention and are not to be construed as limitations on theinvention, as set forth in the appended claims. All parts andpercentages are by weight unless otherwise specified.

Experiment 1

A trial of mercury control by addition of coal additives was completedon a cyclone-fired boiler rated at 280 MW gross electricity production,but capable of short-term peak production of 300 MW. The boilerconfiguration was six cyclone combustors arranged three over three onthe front wall. Each cyclone burns approximately 54,000 lb/h of PowderRiver Basin (PRB) coal at full load. The typical coal sulfur content is0.3% (dry basis) and the coal ash calcium expressed as CaO (dry basis)averages 20%.

NOx emissions are controlled on this Unit by Overfire Air (OFA) portslocated on the rear wall, and by a Selective Catalytic Reduction (SCR)system located upstream of the air preheater. There are no mercurycontrols on this boiler, but a portion of the mercury released duringcombustion is retained by unburned carbon particles captured in theelectrostatic precipitator.

A liquid-phase iodine-containing additive, that was substantially freeof bromine and chlorine, and a solid-phase iron-containing additive wereadded to the furnace. While not wishing to be bound by any theory, theiodine-containing additive is believed to control Hg emissions byenhancing the amount of particle-bound mercury captured. Theiron-containing additive is believed to thicken the molten slag layercontained in the cyclone so that more combustion occurred in thefuel-rich region. Increasing the fuel-rich combustion leads to lowerNO_(x) emissions in the flue gas leaving the boiler. Theiodine-containing additive contained from about 40 to about 50 wt. %iodine. The iron-containing additive contained from about 60 to about 70wt. % total iron, of which from about 30 to about 70 wt. % was ferrousoxide (FeO), and the remaining portion was substantially all eitherferrous ferric oxide (magnetite, Fe₃O₄), ferric oxide (Fe₂O₃), or amixture thereof. Enrichment of the fly ash with reactive iron mayfunction as a catalyst for heterogeneous mercury oxidation.

Depending on access and/or coal yard operational procedures, theadditives were applied to the coal either upstream or downstream of thecrusher house. The solid-phase iron-containing additive was provided ingranular form that was stored in a bulk storage pile located in closeproximity to the iron-containing additive conveying equipment. Theiron-containing additive was transferred from the storage pile to a feedhopper via front-end loader and added to the coal belt via a series ofscrew feeders and bucket elevators.

The liquid iodine-containing additive was delivered in Intermediate BulkContainer (IBC) totes. The liquid material was metered by a chemicalpump to a dispensing nozzle at the top of the bucket elevator where itwas combined with the iron-containing additive prior to being droppedonto the coal supply belt. The feed rate of both the solidiron-containing additive and the liquid iodine-containing additive wascontrolled to an adjustable set-point based on the weight of coal beingfed on the coal belt. The hopper of the conveyor was filled severaltimes a day during normal operations.

This goal of this trial was to demonstrate 20 percent NO_(x) reductionand 40 percent mercury reduction over a three-hour period at full load.The test period included several days of operation with and withoutadditive coal treatment. The initial test period was deemed the“Baseline Tests” conducted to quantify the native or untreated Hgemissions in the stack and the baseline NOx emissions. Then, additivetreatment using both additives began, and combustion improvements wereconfirmed by measuring higher cyclone temperatures with an infraredpyrometer. After a few days of operation with both additives, theexpected NO_(x) reduction was recorded during a one-day combustiontuning test designed to demonstrate that the iron-containing additivewould allow more aggressive cyclone operation than was previouslypossible. Boiler performance was monitored carefully during theemissions test to assure that the emission reductions did not causeother problems. Hg reduction was demonstrated using data from a ThermoFisher Mercury CEM on the stack (downstream from the ESP) and furthervalidated using a modified EPA Method 30-B, “Determination of Mercuryfrom Coal-Fired Combustion Sources Using Carbon Sorbent Traps”, theSorbent Trap Method (STM). Finally, the unit was operated for severaldays in load dispatch mode to demonstrate the long term operability ofthe treated fuel.

Based on historical coal analyses, the uncontrolled Hg emissions withoutthe iodine-containing additive were expected to vary between 5 and 10μg/wscm (0.004 to 0.008 ppmw total Hg in flue gas). Uncontrolledemissions calculated from average coal mercury analysis were 6 μg/wscm(0.005 ppmw) at the air preheater outlet. However, due to the highamount of unburned carbon in the fly ash (10-20%) and low flue gastemperatures (<300° F.), there was significant native mercury removalwithout the iodine-containing additive. During the test period, baselineHg concentrations as measured at the outlet continuous emission monitor(“CEM”) ranged from 1.0 to 1.5 μg/wscm (0.0008 to 0.0013 ppmw).

Prior to iodine-containing additive addition, the total Hg emissionaveraged about 1.1 μg/wscm (0.0009 ppmw). After this baseline period,both the iron- and iodine-containing additives were added to the coal atvarious concentrations. The iron-containing additive was added atbetween about 0.3% and 0.45% by weight of the coal feed. Theiodine-containing additive was added at a rate ranging from about 2 to 7ppmw of the operative chemical to the mass feed rate of the coal. Hgemissions measured at the stack dropped to the range of 0.1 to 0.4μg/wscm (0.0001 to 0.0003 ppmw). Therefore, Hg reduction ranged fromabout 60 to 90 percent additional removal compared to the baselineremoval with just the high-UBC fly ash, with an average of 73 percentadditional reduction when the additive rate was optimized. Overallmercury removal based on the uncontrolled mercury concentration fromcoal mercury was more than 95%. Table 1 summarizes the results achievedat each iodine treatment rate.

The STM results confirmed the Hg-CEM results. Three pairs of baselinemercury (“Hg”) samples were obtained. The Hg concentrations ranged fromabout 1.1 to 1.6 μg/wscm (0.0009 to 0.0013 ppmw), with an average of1.36 μg/wscm (0.0011 ppmw). Three pairs of sorbent traps were alsopulled during iodine-containing additive use. These Hg values rangedfrom about 0.3 to 0.4 μg/wscm (0.0002 to 0.0003 ppmw), with an averageof 0.36 μg/wscm (0.00026 ppmw). The average Hg reduction, compared tobaseline mercury removal, as determined by the STM Method, was 73percent, exactly the same as the additional Hg reduction determined bythe Hg-CEM.

Even though the electrostatic precipitator was already removing about 71percent of the Hg without iodine addition, treatment with theiodine-containing additive caused removal of an additional 73 percent ofthe Hg. With iodine addition, the total Hg removal based on the Hgcontent of the coal was 96 percent with a treatment rate of 7 ppmwiodine to the feed coal. Surprisingly, with a treatment of just 2 ppmwiodine and added iodine/mercury molar ratio of only 30, the totalmercury removal was 90%.

TABLE 1 Experiment 1, Results with SCR^(1,2) Mercury Iodine AddedRemoval Total Addition to Iodine/Hg Uncontrolled Controlled aboveMercury Coal Molar Mercury Mercury Baseline Removal (ppmw) Ratio(μg/wscm)¹ (μg/wscm) (%) (%) 0 0 4.0 1.1  0% 71% 7 106 4.0 0.15 86% 96%5 75 4.0 0.2 82% 95% 3 45 4.0 0.3 73% 93% 2 30 4.0 0.4 64% 90% ¹Averageuncontrolled mercury concentration based on average coal analysis of 72ng/g at full load coal rate and APH outlet gas flow. ²Unit load was 280MW or more for all of the tests with gas temperature at the APH outletranging from about 285 to 300° F.

Experiment 2

Further mercury control testing on the cyclone boiler described abovewas completed during summer while the SCR unit was out of service andthe flue gas redirected around the SCR unit such that the flue gas wasnot exposed to the SCR catalytic surface. During the tests described,only the iodine-containing additive was applied and the iron-containingadditive feed system was entirely shut down. Mercury stack emissionswere monitored by the unit mercury CEM as previously discussed.

Testing was performed over a period of two months at several differentconcentrations of iodine-containing additive and with abromine-containing salt added onto the coal belt. A reference conditionwith no coal additives applied was also tested. Test coal during theentire period was the same as for previous testing, an 8,800 BTU PRBcoal. Flue gas temperatures measured at the air preheater outlet variedfrom 320 to 350° F., significantly higher than during the previous testsdescribed in Experiment 1. For this coal, a number of coal mercuryanalyses averaged 71.95 ng/g total mercury content. This average coalvalue was used as the basis for mercury removal percentages at allconditions over the entire unit from boiler to stack. Note that theremay have been some variation in coal mercury by coal shipment eventhough the same mine supply was maintained throughout the tests.

Each test condition was monitored for a period of days to a full week toensure that the coal supply to each of the cyclones was 100% treated andmercury emissions were stabilized. Table 2 summarizes the data obtainedwith the unit at full load conditions. The iodine-containing additivewas applied at the listed concentrations. The bromine-containingadditive was applied at two concentrations.

TABLE 2 Experiment 2, Results with SCR Bypassed^(1,2) Iodine or AddedMercury Bromine Iodine or Removal Total Addition to Bromine:HgUncontrolled Controlled above Mercury Coal Molar Mercury MercuryBaseline Removal (ppmw) Ratio (μg/wscm)¹ (μg/wscm) (%) (%) 0 0 6.0 2.9 0% 51% 20 302 6.0 0.5 83% 92% 12 181 6.0 0.9 69% 85% 8 121 6.0 1.1 62%82% 6 91 6.0 0.9 69% 85% 15 (Br) 359 (Br) 6.0 1.0 66% 83%  6 (Br) 144(Br) 6.0 1.4 52% 77% ¹Average uncontrolled mercury concentration basedon average coal analysis of 72 ng/g at full load coal rate and APHoutlet gas flow. ²Unit load was 280 MW or more for all of the tests withgas temperature at the APH outlet ranging from 320 to 350° F.

During the tests, the unit fly ash UBC percentage varied from 6% to 25%as measured post-test by fly ash taken from the electrostaticprecipitator hoppers. Exact UBC during each test could not be determinedbased on hopper UBC content post-test, since hopper ash may not beentirely evacuated until days after it is removed from the ESPcollection plates. Flue gas temperature at the inlet to the particulatecontrol (ESP) varied from about 320 to 350° F. This was higher than theprevious tests with the SCR in service, primarily due to summer vs.winter ambient conditions and the need to maintain peak load forextended periods.

Mercury removal, as calculated by the total from coal analysis tomeasured outlet mercury CEM, varied from 85 to 92%. With no treatment,mercury removal was approximately 51%.

This result shows that treatment by the iodine-containing additive iseffective at higher process temperatures (e.g., from about 320 to 350°F. at the ESP inlet) and without the benefit of an SCR catalyst.

Higher UBC is known to assist with native mercury capture byphysisorption of oxidized mercury onto UBC carbon. However, at greaterthan 320° F., the physisorption of vapor mercury declines significantly.Thus, the addition of the iodine-containing additive, by itself, with noSCR catalysis effect was shown to improve higher temperature mercuryremoval to 90% or higher, but the form of mercury removed(particle-bound or vapor species) was not determined.

The bromine-containing additive treatment also increased mercury removalfrom 77 to 83% compared to 51% with no treatment. This result wasunexpected on the basis of previous experience and industryunderstanding from other test sites. The expectation was that asignificantly higher level of bromine addition would be required torealize a high rate of mercury removal. Higher UBC carbon in the cycloneboiler ash may be responsible for the excellent bromine performance withno SCR, but data on real-time in-situ UBC was not available to confirmthis hypothesis.

Since mercury emission was measured at the stack, the speciation andform of mercury upstream was not explicitly measured, so the differencesin mercury speciation as a result of iodine and bromine treatment werenot evaluated by these tests.

Experiment 3

A series of tests were performed at Site A, a 360 MW coal-fired powerplant firing Powder River Basin (“PRB”) coal. The tests compared mercuryremoval when iodine was added to the coal at two concentrations(Experiment 3) and when a bromide additive was applied to the PRB coal(Experiment 4). The plant was firing 100% PRB coal before the testsbegan. The plant was equipped with a lime spray dryer (“SDA”) followedby a fabric filter (“FF”) baghouse (collectively “SDA/FF”) for controlof SO₂ and particulates. During the trial, semi-continuous mercuryanalyzers were located at the outlet of the air preheater upstream ofthe SDA and FF baghouse at the stack outlet.

The iodine content of the coal feed was provided by coal blending. Twoblend ratios of PRB Black Thunder coal (“Black Thunder” or “BT”) andhigher iodine coal (“Coal B”) were tested to evaluate the influence ofthe bituminous coal on mercury removal by native fly ash. The firstblend ratio was nominally 92.7% Black Thunder and the balance was CoalB. The second blend ratio consisted of 85.6% Black Thunder and thebalance Coal B. Coal sulfur content for both blends was 0.4% dry basis.Coal ash calcium (CaO, dry basis) was 17.2% for the first and 18.4% forthe second blend. The unit operated normally during the week except thatone of the five coal mills, Mill C, was out of service.

Vapor-phase mercury concentrations were monitored at the outlet of theair preheater on the A-side of the unit and at the stack. A summary ofthe tests, including the blending ratios and the average mercuryconcentrations, is presented in Table 3 and FIG. 7. There were someoperational problems associated with the inlet mercury analyzerimmediately prior to beginning the first coal blending test that mayhave compromised the inlet concentrations measured. Therefore, atriplicate set of EPA Draft M324 (sorbent trap) samples were collectedat the preheater outlet location for secondary mercury measurement.During the second test, simultaneous M324 samples were collected at theair pre-heater and stack.

TABLE 3 Vapor-Phase Mercury during Coal Blending Tests at Site A TotalIodine Iodine Outlet enrichment (ppmw Hg Inlet Hg Inlet Hg⁰ Outlet HgHg⁰ (ppmw of of coal Removal Test Coal (μg/Nm³) (μg/Nm³⁾ (μg/Nm³)(μg/Nm³) coal feed) feed) (%) 100% JR 9.8 8.1 10.4 9.6 0.0 0.4 −6^(b)PRB 7.3% Coal B NA 7.7  3.6 3.3 0.4 0.8 NA^(a) 92.7% BT (7.24) ^(M324)(50) ^(M324) 14.4% Coal 5.8 5.4  1.4 1.4 0.7 1.1 76 B (5.28) ^(M324)(0.97) ^(M324) (81) ^(M324) 85.6% BT All concentrations shown correctedto 3% molecular oxygen. ^(a)Analyzer operational problems-data suspect^(b)Analyzer calibration drift, 0% Hg removal. ^(M324) Mercuryconcentration measured with EPA Draft M324

There was no measurable vapor-phase mercury removal measured whilefiring 100% Jacobs Ranch coal. At the first blend ratio, the mercuryremoval across the SDA-FF increased to 50%. The mercury removal duringthe second blend test increased to 76% (81% based upon M324 sorbent trapsamples).

Coal B samples were tested for mineral and halogen constituents afterthe trial. Coal B samples were tested at 4.9 ppmw iodine in the coal byneutron activation analysis (NAA). The baseline PRB samples typicallyaverage 0.4 ppmw iodine. The resulting enrichment of iodine is shown inTable 2 above.

Experiment 4

One additional test at Site A was to add sodium bromide (NaBr) to thecoal to increase the bromine concentration in the flue gas in an attemptto enhance mercury capture. No activated carbon was injected during thistest.

NaBr was applied to the coal at the crusher house prior to entering thetransfer house and coal bunkers. At this chemical injection location, itwas estimated that it would take 4-5 hours before the “treated” coalwould be fired in the boiler. The chemical additive was applied to thecoal continuously for a period of 48 hours prior to injecting activatedcarbon to ensure that the entire system was “conditioned” with theadditive.

During testing with NaBr injection, the unit was burning coal from theJacobs Ranch mine. At normal operating conditions, the coal yielded atotal vapor-phase mercury concentration of about 18 to about 22 μg/Nm³at the outlet of the air preheater with 70-90% in elemental form. Duringthe chemical additive tests, the fraction of elemental mercury at theair preheater outlet decreased to about 20-30%.

Although the fraction of oxidized mercury at the inlet of the SDAincreased substantially, no increase in mercury removal across thesystem was noted. The fraction of oxidized mercury at the outlet of thefabric filter was also lower (nominally 80% elemental mercury comparedto typically >90% elemental mercury when NaBr was not present with thecoal).

Experiments 3 and 4 illustrate the difference between the two halogenadditives. In the case of iodine added by means of the blend coal, themercury was being removed across the SDA-FF at up to 76% of totalmercury, even though there was less than 1% UBC content in the ash/spraydryer solids. In the case of the bromine additive, there was increasedvapor oxidized mercury at the SDA inlet but mainly elemental vapormercury measured at the outlet with no increased mercury capture. Incombination with iodine treatment on the coal, the SDA-FF provides finespray solids and full mixing in a temperature range where heterogeneousreaction can occur.

Experiment 5

Coal blending tests were completed at other PRB coal-fired power plants,using various western bituminous coals in blend ratio to PRB of up to20%. The results are shown in Table 4 below. None of the westernbituminous blend coals in these trials that exhibited any significantmercury removal except the Coal B that is described in Experiments 3 and4 above.

TABLE 4 Results of Western Bituminous Blend Tests For Mercury ControlBlend UBC Mercury Coal APC Carbon Blended Coal Removal Test/Unit in PRBEquipment (% of ash) Iodine ppm (%) Site B ColoWyo, 20% SDA/ESP <1.0<0.5 ⁽¹⁾ 0 Site B TwentyMile, 16% SDA/ESP 0.6 <0.5 ⁽¹⁾ 0 ⁽¹⁾ Nativeiodine in western bituminous coals typically is less than 0.5 ppmw.SDA—Spray Dryer Absorber, SO₂ Control ESP—Electrostatic Precipitator

Experiment 6

Another test site for coal blending, Site D, fires subbituminous PRBcoal and is configured with low-NOx burners and selective catalyticreduction (“SCR”) unit for NOx control, a spray dryer absorber (“SDA”)for SO₂ control, and a fabric filter (“FF”) for particulate control. Thetest matrix included evaluating each coal at 7% and 14% higher iodinecoal (Coal B) mixed with a balance of PRB. Each blend test was scheduledfor nominally 16 hours with eight hours of system recovery time betweentests. Coal A had a native iodine content of less than about 0.5 ppmwwhile coal B had a native iodine content of about 4.9 ppmw. Coal Asulfur content was 0.6 to 0.8%, dry basis. The blend coals averaged0.65% sulfur. The coal ash calcium content, based on typical analysis ofCoals A and B, was between 17 and 20% (CaO, dry basis).

For the first blend test (Coal B at 7.2%), there was a significantdecrease in both the SDA inlet and stack mercury concentrations at thebeginning of the test. However, there was no increase in oxidizedmercury (Hg⁺²), which would suggest that, if this decrease were duesolely to the coal blend, mercury removal occurred in the particulatephase before reaching the SDA inlet sampling location. Based on thisassumption, the mercury removal for the first test was about 50%,calculated using the mercury concentration at the beginning of the testand at its lowest point during the test. If removal is calculatedstrictly based on SDA inlet and outlet mercury concentrations, thenremoval increased from 10% to 27% due to coal blending.

During the second test (Coal B at 13.2%), the stack mercury levelsgradually decreased, but the inlet did not. Based on the SDA inlet andstack concentrations, the mercury removal for the second test increasedfrom about 15% to 51%. The iodine content of the coals was not analyzedat the time of testing, but the iodine content of Coal B has since beenanalyzed. Iodine enrichment compared to the baseline PRB coal wasapproximately 0.7 ppmw at the 14% blend ratio, based on typical iodineanalysis for Coal B. The iodine/mercury molar ratio was approximately30. Surprisingly, mercury removal was more than 50% even at this lowadditive rate.

Experiment 7

A trial of mercury control when firing an iodine treated coal wascompleted on a 70 MW, wall-fired unit firing a Powder River Basin coal.The purpose of this test was to compare the mercury removal of thetreated coal product on mercury emissions compared to the identical coalat the same process conditions without treatment. The coal was treatedremotely by application of an aqueous iodine-containing solution byspray contact with the coal. A unit train was loaded with about halfuntreated and half treated coal. The level of treatment based on coalweight and chemical applied was 7.6 ppmw of iodine in the as-loadedcoal. The concentrated chemical spray was applied to substantially allof the coal and was well-distributed.

At the power plant, the untreated coal from this unit train was firedfor six days and then the first treated coal was introduced. Treatedcoal was then burned exclusively in this unit for another seven days.Coal sulfur content averaged 0.35%, dry basis. Coal ash calcium contentwas 20.9%, dry basis, CaO.

Coal samples taken at the plant from the coal feed to the boiler wereanalyzed for halogen content by neutron activation analysis (NAA).Samples during the baseline period averaged 26.0 μg/g chlorineas-received, 1.2 μg/g bromine and 0.4 μg/g iodine. Samples taken whilefiring treated coal averaged 18.9 μg/g chlorine as-received, 1.1 μg/gbromine and 3.0 μg/g iodine. The results for iodine indicated lossduring transit and handling (7.6 μg/g as loaded and 3.0 as-received).However, the coal sampling and analytical frequency was lower thannecessary to conclusively determine this.

The plant pollution control equipment consisted of a cold-sideelectrostatic precipitator operating at an inlet flue gas temperature of360° F. to 400° F. The level of unburned carbon (loss-on-ignition) was0.7% or essentially none in the PRB fly ash. In addition, the mercuryspeciation as measured by the outlet mercury monitor was initiallyalmost all elemental mercury. These conditions were expected to beextremely problematic for conventional mercury control such as activatedcarbon injection (ACI) or bromine treatment of coal. For ACI, thetemperature was too high for substantial elemental mercury sorptionexcept at higher injection rates with halogenated activated carbon. Thiswould be expensive and would add carbon detrimentally into the fly ash.Bromine treatment of coal would be expected to increase the oxidation ofmercury when applied as typically practiced at 30 to 100 ppm on thecoal, but the lack of unburned carbon in the fly ash would limit captureof the oxidized mercury species. It would not be unexpected to see nomercury capture for this condition with bromine added to the coal.

A modular rack Thermo Fisher mercury continuous emission monitor(Hg-CEM) was installed at the ESP outlet (ID fan inlet) to measure thetotal and elemental mercury in the flue gas. The monitor directly readmercury concentration in the flue gas on one-minute average intervals inunits of micrograms mercury per standard cubic meter of flue gas, wetbasis (μg/wscm).

The treated coal first reached the boiler from only one of 3 bunkers andthe mercury concentration at full load rapidly decreased from 5 to 2.6μg/wscm (0.0041 to 0.0021 ppmw in the flue gas) or about 50% reduction.After all the coal feed switched to treated, the mercury decreasedslightly more and remained lower. Overall, the average baseline mercuryconcentration measured at the stack outlet when initially burning thecoal with no iodine treatment was about 5.5 μg/wscm (0.0045 ppmw) athigh load above 70 MW and 1.7 μg/wscm (0.0014 ppmw) at low load of about45 MW. When firing treated coal, the high load Hg concentration averagedabout 2.6 μg/wscm (0.0021 ppmw) and the low load about 0.8 μg/wscm(0.0006 ppmw). The use of treated coal reduced mercury emission by about53%. In addition, episodes of extreme mercury spikes during hightemperature excursions related to soot blowing were substantiallyeliminated. After the unit came back from an outage, the regular coalfeed (untreated) was resumed and the mercury emissions returned tobaseline of about 5.5 μg/wscm (0.0045 ppmw) at full load.

In addition to reducing the total mercury by converting to a particulateform, the additive also appears to have converted the majority of theremaining vapor phase mercury to an oxidized form. This creates anopportunity to obtain additional mercury capture with the injection of alow-cost untreated sorbent. If the mercury were not converted to anoxidized form, additional trimming of the mercury emissions wouldrequire a more expensive brominated sorbent.

In order to further validate the mercury measurements, a set ofindependent emissions tests were completed using a sorbent trap method(EPA Method 30B). The sorbent trap emissions agreed well with the Hg-CEMthroughout the trial.

Total mercury removal in this trial was more than 50% for a difficultprocess condition (PRB coal, gas temperature 350 to 400° F., no UBC andundersized electrostatic precipitator) for which zero or minimal removalwould be expected by either injection of activated carbon or brominetreatment of feed coal.

Experiment 8

A trial of mercury control by addition of coal additives was completedon a cyclone-fired boiler rated at 600 MW gross electricity production,but capable of short-term peak production of 620 MW. The boilerconfiguration was 14 cyclone combustors arranged three over four on thefront and rear walls. Each cyclone burns approximately 50,000 lb/h ofPowder River Basin (PRB) coal at full load. The coal sulfur content was0.3% (dry basis) and the coal ash calcium content (CaO) averaged 22%(dry basis).

NO_(x) emissions are controlled on this unit by Overfire Air (OFA) portslocated on the front and rear walls, and by a Selective CatalyticReduction (SCR) system located upstream of the air preheater. There areno Hg controls on this boiler, but a portion of the mercury releasedduring combustion is retained by unburned carbon particles captured inthe electrostatic precipitator.

A liquid-phase iodine-containing additive, that was substantially freeof bromine and chlorine, and a solid-phase iron-containing additive wereadded to the furnace. The additives were applied to the coal upstream ofthe crusher house. The solid-phase iron-containing additive was providedin granular form that was stored in a bulk storage pile located in closeproximity to the iron-containing additive conveying equipment. Theliquid iodine-containing additive was delivered in Intermediate BulkContainer (IBC) totes. The liquid material was metered by a chemicalpump to a dispensing nozzle at the top of the bucket elevator where itwas combined with the iron-containing additive prior to being droppedonto the coal supply belt. The feed rate of both the solidiron-containing additive and the liquid iodine-containing additive wascontrolled to an adjustable set-point based on the weight of coal beingfed on the coal belt.

The test period included several days of operation with and withoutadditive coal treatment. The initial test period was deemed the“Baseline Tests” conducted to quantify the native or untreated Hgemissions in the stack and the baseline NO_(x) emissions. Then, additivetreatment using both additives began.

Mercury reduction was demonstrated using data from a Thermo FisherMercury CEM on the stack (downstream from the ESP). Based on historicalcoal analyses, the uncontrolled Hg emissions were expected to varybetween 5 and 10 μg/wscm. Coal mercury content was analyzed during thetrial and averaged 68.7 ng/g. Based on this and the flue gas flow rate,the expected mercury concentration in the flue gas at the air preheateroutlet was 5.8 μg/wscm (0.0005 ppmw).

Due to the high amount of unburned carbon in the fly ash (10-20%) andlow flue gas temperatures (<300° F.), there was significant nativemercury removal without the iodine additive. During the baseline period,vapor-phase Hg concentrations as measured by the stack outlet Hg-CEMranged from 0.2 to 1.1 μg/wscm (0.0002 to 0.0009 ppmw) with an averageof about 0.6 μg/wscm. Iodine was then added to the coal feed at variousconcentrations and mercury emissions dropped to the range of 0.03 to0.13 μg/wscm (0.00002 to 0.0001 ppmw). Overall mercury removal, coalpile to stack, at this condition was >98%. Additional mercury reductionfrom the baseline condition ranged from 78 to 95 percent, with anaverage of 78 percent reduction at a feed rate equivalent to 3 ppm byweight of iodine on the coal.

Sorbent Trap method (STMs) using a modified EPA Method 30-B wereconducted during baseline tests to substantiate the Hg-CEM measurements.The STMs all agreed with the Hg-CEM agreed within specified limits (%Relative Accuracy<20%). During additive injection, STMs were notconducted at the extremely low mercury conditions, due to theprohibitively long STM sample times in order to collect enough mercuryto be above the detection limit of the analysis.

This experiment demonstrates the ability to economically achieve acritical 90% mercury removal with only 3 ppmw iodine in combination withiron additive added to the coal feed, without the need for expensiveadditional mercury control equipment.

TABLE 5 Experiment 8 Results Mercury Iodine Removal Total Addition toAdded Uncontrolled Controlled above Mercury Coal Iodine/Hg MercuryMercury Baseline Removal (ppmw) Molar Ratio (μg/wscm)¹ (μg/wscm) (%) (%)0 0 5.8 0.6  0% 90% 3 47 5.8 0.13 78% 98% ¹Average uncontrolled mercuryconcentration based on average coal analysis of 69 ng/g at full loadcoal rate and APH outlet gas flow.

Experiment 9

The objective of three tests, described below, was to assess thestability of elemental iodine adsorbed on a porous carbonaceous material(i.e., activated carbon) by exposing the loaded carbon to differenttemperatures for extended periods of time.

In the first test, elemental iodine was formed by oxidizing 1000 ppmiodide solution by acidifying it, and adding a small amount of hydrogenperoxide. The iodine solution was then passed through a bed of activatedcarbon in a filter funnel. The carbon is considered to be loaded whenthe yellow color of iodine in water breaks through the carbon bed. Fourhundred twenty five milligrams of iodine per gram of carbon was adsorbedon Sabre™ powdered activated carbon (“PAC”) with this method.

The loaded carbon was dried, and a weighed amount placed in anErlenmeyer flask with the neck plugged with a filter paper saturatedwith soluble starch solution. The temperature of the flask was raised to˜50° C. and held for one hour. Only a faint purple color developed onthe starch paper indicating that only a trace of iodine was driven offthe carbon at this temperature

In a second test, Sabre™ PAC was loaded with iodine using the iodinenumber procedure. This test indicated that 1,079 mg of iodine was sorbedper gram of carbon. Note that in this procedure the carbon filter cakeis not washed; thus some the iodine can be held interstitially and isnot strictly sorbed to the carbon.

A slight purple color formed on the starch paper at a temperature of 30°C. and significant color and small iodine crystals developed on thepaper when the temperature reached 50° C. The temperature was raised toabout 80° C., and dense iodine vapors formed above the carbon.

Once cooled, a 0.25 gram portion was reacted with 50 ml of an alkalinehydrogen peroxide solution for 15 minutes to remove the iodine from thecarbon by reducing it to iodide. The percentage of iodine retained onthe carbon after heating to ˜80° C. was calculated to be about 200 mg/gof carbon.

In a third test, an iodine solution was made so that up to 500 mg/g wasavailable when reacted with two grams of Sabre™ PAC. After washing,filtering, and drying, a portion was analyzed to determine the amount ofiodine adsorbed. About 360 mg I₂/g carbon was adsorbed.

The method of stripping the iodine from activated carbon by reducing itto iodide with hydrogen peroxide appears to be quantitative as testsperformed on the stripped carbon with isopropyl alcohol, which haspreviously been shown to strip iodine from activated carbon, werenegative.

Another portion of the loaded carbon was heated to 50° C. and held atthat temperature for 1.5 hours with only a small amount of iodineliberated as indicated by the starch paper. The carbon was cooled andstripped of iodine. The iodide concentration of the strip solution wasmeasured. The amount of iodine retained by the carbon after heating to50° C. was found to be 280 mg I₂/g Sabre™ PAC.

Another portion of iodine loaded carbon was heated to more than 80° C.to drive off more iodine, and the carbon analyzed as in the aboveparagraph. The amount of iodine retained after this extreme heating was320 mg I₂/g Sabre™ PAC.

These tests indicate that Sabre™ PAC holds between 200 and 300 mg ofiodine per gram of carbon with sufficient tenacity to be stable up toabout 80° C. and greater amounts are fairly stable at 25° C.

Significantly, loadings of up to 360 mg/g were achieved. In later testswith some high microporosity carbons, loadings of 50 to 100% wereobtained. While the iodine becomes less energetically adsorbed and mayevolve some vapor off the carbon at very high loadings, these testsdemonstrate that a high quality carbon can be used since the quantitiesrequired are no more than about 3 lbs. per lb. of iodine. Also, in someconfigurations, the iodine could be desorbed off the carbon and into theflue gas by heating, for example, and the carbon re-used.

Experiment 10

A trial was conducted to evaluate mercury removal at a 450 MW coal-firedcyclone boiler during treatment of coal with an iodine-containingadditive. The plant was configured with an SCR, rotary air preheater(APH) and a cold-side ESP. The plant was burning a mixture of 85% PRBand 15% low-sulfur Eastern bituminous coal. Coal sulfur content was0.4%, dry basis and coal ash calcium content was about 17% as CaO, drybasis.

A liquid-phase iodine-containing additive, substantially free of bromineand chlorine, was added to the coal at 6 to 13 ppm by weight of halogento the coal feed for a period of three days. Total and speciated mercury(elemental and oxidized) was measured continuously using a Thermo FisherMercury CEM on the stack (downstream from the ESP). Prior to halogenaddition, the total mercury was 2 μg/wscm and the oxidized mercuryfraction was approximately 50%. Iodine was added to the coal at a firstrate of 6 ppm_(w) and then at a second rate as high as 13 ppm_(w).Injection of halogen immediately increased the Hg oxidation at the stackfrom 50% to 90%. However, total mercury emissions as measured at thestack were not substantially affected even after 3 days of injection.Table 6 summarizes the trial results.

TABLE 6 Experiment 10 Results Mercury Iodine Removal Addition TotalOxidized above to Coal Mercury Mercury Baseline (ppmw) (μg/wscm)¹ (%)(%) 0 (Baseline) 2.0 30-60  0% 6 1.5-2.0 70-90 <25% 13 1.5-2.0  90-100<25%

The SO₂ emissions during the testing were monitored by the stackcontinuous emission monitors. The SO₂ emissions during the trial were0.75 to 0.8 lb/MMBtu. The air preheater exit temperature fluctuatedbetween about 260° F. at 350 MW and 320° F. at 450 MW. The oxidationrate of SO₂ across the SCR was estimated to be 1.9% at full load and0.3% at low load, based on prior measurements of SO₃ made at the SCRinlet and outlet. The formation and deposition of SO₃ through the SCR tothe stack was modeled to estimate SO₃ concentrations after the SCR atlow load and full load. At full load, the SO₃ at the APH outlet wasestimated to be about 7 ppmvd, but at low load (350 MW), less than 1ppmvd. Table 7 summarizes the model results.

TABLE 7 SO₃ Model Prediction for 85% PRB blend Load, MW 450 350 ESPInlet Temperature 320 260 SO₃, ppmvd at 3% O₂ SCR inlet 2.9 2.9 SCRoutlet 11.3 4.2 ESP inlet 6.9 0.4 Stack 4.4 0.3

The SO₃ at the outlet of the APH (ESP inlet) is lower at low load fortwo reasons (1) lower temperatures in the SCR mean less SO₂ will beoxidized and (2) lower temperatures at the APH outlet mean more removalof SO₃ across the APH. At low load with iodine treatment of the coal,reduced SO₂ to SO₃ oxidation plus reduced ammonia for deNOx, the mercurywas 100% oxidized. At full load, however, there was an excess of SO₃ ofas much as 7 ppmv that blocks mercury reaction on ESP fly ash surfacesites.

Doubling the rate of halogen coal additive in this case increased themercury oxidized fraction, but was not effective in increasing mercuryremoval (due to the excess SO₃). This trial illustrates again that verylow levels of halogen (6 ppmw of coal feed) are required with SCR tooxidize the majority of mercury, but it also demonstrates thesensitivity of mercury capture to SO₃ levels at the ESP and, in thiscase, the undesirable SO₂ to SO₃ oxidation occurring in the SCR. Eventhough a low-sulfur coal is being fired, the overall emissions of SO₂ islow and the mercury is present almost entirely in an oxidized form whena halogen coal additive is present, the catalytic formation of SO₃across the SCR and its deposition on mercury capture surfaces,especially in the ESP, are still very detrimental to mercury retentionin the fly ash.

A number of variations and modifications of the disclosure can be used.It would be possible to provide for some features of the disclosurewithout providing others.

For example in one alternative embodiment, coal containing naturallyhigh concentrations of iodine (e.g., greater than about 2 ppmw, evenmore typically greater than about 3 ppmw, and even more typicallygreater than about 4 ppmw) is blended with the feedstock coal having noor low concentrations of iodine (e.g., no more than about 2 ppmw andeven more commonly no more than about 1 ppm by weight) to increasemercury removal. The coal, when fired, can have high or low UBC contentwithout adversely impacting mercury removal.

The present disclosure, in various aspects, embodiments, andconfigurations, includes components, methods, processes, systems and/orapparatus substantially as depicted and described herein, includingvarious aspects, embodiments, configurations, subcombinations, andsubsets thereof. Those of skill in the art will understand how to makeand use the various aspects, aspects, embodiments, and configurations,after understanding the present disclosure. The present disclosure, invarious aspects, embodiments, and configurations, includes providingdevices and processes in the absence of items not depicted and/ordescribed herein or in various aspects, embodiments, and configurationshereof, including in the absence of such items as may have been used inprevious devices or processes, e.g., for improving performance,achieving ease and\or reducing cost of implementation.

The foregoing discussion of the disclosure has been presented forpurposes of illustration and description. The foregoing is not intendedto limit the disclosure to the form or forms disclosed herein. In theforegoing Detailed Description for example, various features of thedisclosure are grouped together in one or more, aspects, embodiments,and configurations for the purpose of streamlining the disclosure. Thefeatures of the aspects, embodiments, and configurations of thedisclosure may be combined in alternate aspects, embodiments, andconfigurations other than those discussed above. This method ofdisclosure is not to be interpreted as reflecting an intention that theclaimed disclosure requires more features than are expressly recited ineach claim. Rather, as the following claims reflect, inventive aspectslie in less than all features of a single foregoing disclosed aspects,embodiments, and configurations. Thus, the following claims are herebyincorporated into this Detailed Description, with each claim standing onits own as a separate preferred embodiment of the disclosure.

Moreover, though the description of the disclosure has includeddescription of one or more aspects, embodiments, or configurations andcertain variations and modifications, other variations, combinations,and modifications are within the scope of the disclosure, e.g., as maybe within the skill and knowledge of those in the art, afterunderstanding the present disclosure. It is intended to obtain rightswhich include alternative aspects, embodiments, and configurations tothe extent permitted, including alternate, interchangeable and/orequivalent structures, functions, ranges or steps to those claimed,whether or not such alternate, interchangeable and/or equivalentstructures, functions, ranges or steps are disclosed herein, and withoutintending to publicly dedicate any patentable subject matter.

1. A method, comprising: generating from a mercury-containing feedmaterial a mercury-containing gas stream comprising vapor-phaseelemental mercury and a vapor-phase halogen; passing themercury-containing gas stream through a scrubber to remove at least aportion of the vapor-phase halogen and/or a halogen-containingderivative thereof and form a halogen-containing scrubbing medium and atreated gas stream; and removing the halogen from the halogen-containingscrubbing medium to form a treated scrubbing medium for recycle to thescrubber and a removed halogen and/or halogen-containing material. 2.The method of claim 1, wherein the halogen in the removed halogen and/orhalogen-containing material is one or more of bromine and iodine andwherein the scrubber is a wet or dry scrubber.
 3. The method of claim 1,wherein the scrubber removes at least most of the vapor-phase halogenfrom the gas stream and wherein the scrubber removes at least most of anacid gas from the gas stream.
 4. The method of claim 1, wherein at leastmost of the halogen on the halogen-containing scrubbing medium isremoved as the removed halogen and/or halogen-containing material. 5.The method of claim 1, wherein the scrubber is a wet scrubber and iscapable of removing one or more of HCl, HBr, and HF from the gas stream.6. The method of claim 1, wherein the halogen is removed from thehalogen-containing scrubbing medium by one or more of membraneseparation, precipitation, adsorption, and/or absorption.
 7. The methodof claim 6, wherein the halogen-containing scrubbing medium is contactedwith an oxidant to assist halogen removal.
 8. The method of claim 1,wherein the scrubber is a wet scrubber and wherein the halogen isremoved from the halogen-containing scrubbing medium by one or more ofan ion exchange resin, solvent extraction, adsorption, absorption,precipitation, and membrane filtration.
 9. The method of claim 1,wherein the halogen can oxidize elemental mercury in the gas stream andfurther comprising: recycling the removed halogen and/orhalogen-containing material to the generating step, whereby thevapor-phase halogen is derived from the removed halogen and/orhalogen-containing material.
 10. The method of claim 9, furthercomprising regenerating the removed halogen and/or halogen-containingmaterial prior to recycle.
 11. The method of claim 1, wherein aconcentration of the vapor-phase halogen in the treated gas stream is nomore than about 25 ppm.
 12. The method of claim 1, wherein thevapor-phase halogen is iodide.
 13. The method of claim 1, wherein thevapor-phase halogen is bromide.
 14. The method of claim 1, wherein themercury-containing feed material is coal, wherein the mercury-containinggas stream is formed by combusting coal and wherein the vapor-phasehalogen is formed from a native halogen-content of the coal.
 15. Themethod of claim 1, wherein the mercury-containing feed material is coal,wherein the mercury-containing gas stream is formed by combusting coal,and wherein the vapor-phase halogen is formed from a halogen-containingadditive combusted with the coal.
 16. The method of claim 1, wherein themercury-containing feed material is coal, wherein the mercury-containinggas stream is formed by combusting coal, and wherein the vapor-phasehalogen is introduced into the gas stream downstream of a coalcombustion zone.